Natural Gas Liquefaction Process

ABSTRACT

A gas processing facility for the liquefaction of a natural gas feed stream is provided. The facility comprises a gas separation unit having at least one fractionation vessel. The gas separation unit employs adsorbent beds for adsorptive kinetic separation. The adsorbent beds release a methane-rich gas feed stream. The facility also includes a high-pressure expander cycle refrigeration system. The refrigeration system compresses the methane-rich gas feed stream to a pressure greater than about 1,000 psia. The refrigeration system also chills the methane-rich gas feed stream in one or more coolers, and then expands the chilled gas feed stream to form a liquefied product stream. Processes for liquefying a natural gas feed stream using AKS and a high-pressure expander cycle refrigeration system are also provided herein. Such processes allow for the formation of LNG using a facility having less weight than conventional facilities.

CROSS REFERENCE TO RELATED APPLICATION

This application claims the benefit of U.S. Provisional PatentApplication 61/521,657, filed Aug. 9, 2011 entitled NATURAL GASLIQUEFACTION PROCESS, the entirety of which is incorporated by referenceherein.

BACKGROUND OF THE INVENTION

This section is intended to introduce various aspects of the art, whichmay be associated with exemplary embodiments of the present disclosure.This discussion is believed to assist in providing a framework tofacilitate a better understanding of particular aspects of the presentdisclosure. Accordingly, it should be understood that this sectionshould be read in this light, and not necessarily as admissions of priorart.

FIELD OF THE INVENTION

The present invention relates to the processing of gaseous fluids. Morespecifically, the present invention relates to the liquefaction ofnatural gas, particularly hydrocarbon gases produced in remotelocations.

DISCUSSION OF TECHNOLOGY

As the world's demand for fossil fuels increases, energy companies findthemselves pursuing hydrocarbon resources located in more remote andhostile areas of the world, both onshore and offshore. This includes thepursuit of natural gas.

Because of its clean burning qualities, natural gas has become widelyused in recent years. However, many sources of natural gas are locatedin geographical areas that are great distances from commercial markets.In some instances, a pipeline is available or may be constructed fortransporting produced natural gas to a commercial market. However, whena pipeline is not available for transportation, produced natural gas isoften transported via large ocean-going vessels.

To maximize gas volumes for transportation, the gas is frequently takenthrough a liquefaction process. The liquefied natural gas (“LNG”) isformed by chilling very light hydrocarbons, e.g., gases containingmethane, to approximately −160° C. The liquefied gas may be stored atambient pressure in special, cryogenic tanks disposed on large ships.Alternatively, LNG may be liquefied at an increased pressure and at awarmer temperature, i.e., above −160° C., in which case it is known asPressurized LNG (“PLNG”). For purposes of the present disclosure, PLNGand LNG may be referred to collectively as “LNG.”

As currently developed, gas is taken through a liquefaction process at alocation proximate the point of production. This means that a largegathering and liquefaction center is erected in the producing country.Alternatively, the liquefaction process may take place offshore on aplatform or vessel, such as a floating production, storage andoffloading (FPSO) vessel. Currently, large liquefaction facilities existin Qatar, Russia (Sakhalin Island), Indonesia, and other countries.Several significant LNG terminals are either under construction in orare presently planned for Australia.

After natural gas is chilled to a liquid state, the hydrocarbon productis loaded onto marine transport vessels. Such vessels are known as LNGtankers. The chilling of natural gas into a liquefied state enables thetransport of much larger volumes of gas.

In the design of an LNG plant, one of the most important considerationsis the process for converting the natural gas feed stream into LNG.Currently, the most common liquefaction processes use some form ofrefrigeration system. Although many refrigeration cycles have been usedto liquefy natural gas, there are three types of refrigeration systemsmost commonly used in LNG plants.

The first type of system is known as a “cascade cycle.” A cascade cycleuses multiple, single-component refrigerants in heat exchangers arrangedprogressively to reduce the temperature of the gas to a liquefactiontemperature. The second type of refrigeration system is the“multi-component refrigeration cycle.” This system uses amulti-component refrigerant in specially designed exchangers. The thirdtype of system is the “expander cycle.” The expander cycle systemexpands gas from feed gas pressure to a low pressure, producing acorresponding reduction in temperature under Boyle's Law. Most naturalgas liquefaction cycles use variations or combinations of these threebasic types.

A recent variant of the expander cycle is the High Pressure ExpanderCycle. This system provides a liquefaction process that is moreefficient and compact than the cycles described above. As a result, ithas become an attractive option for remote or offshore applications.

A limitation to the use of any liquefaction system is the presence ofcontaminants in the natural gas stream. Raw natural gas produced fromsubsurface reservoirs typically contains components that are undesirablein the LNG process. Such components include water, carbon dioxide andhydrogen sulfide. Water and CO₂ should be removed because they willfreeze at liquefaction temperatures and plug the liquefaction equipment.H₂S should be removed as it may have adverse safety impacts or mayadversely affect the LNG product specifications. Therefore, natural gasproduction is typically treated before liquefaction to remove theundesirable components or contaminants.

When H₂S and CO₂ are produced as part of a hydrocarbon gas stream (suchas methane or ethane), the raw gas stream is sometimes referred to as“sour gas.” The H₂S and CO₂ are often referred to together as “acidgases.” Processes have been devised to remove acid gases from a rawnatural gas stream. In some instances, cryogenic gas processing is used.This involves chilling the gas stream in a large cryogenic vessel sothat CO₂ and H₂S components drop out as solids. The hydrocarboncomponents are distilled out of the vessel. This process typicallyrequires that the raw gas stream undergo dehydration before cryogenicseparation.

As an alternative, the hydrocarbon gas stream may be treated with asolvent. Solvents may include chemical solvents such as amines. Examplesof amines used in sour gas treatment include monoethanol amine (MEA),diethanol amine (DEA), and methyl diethanol amine (MDEA). Physicalsolvents are sometimes used in lieu of amine solvents. Examples ofphysical solvents include Selexol® and Rectisol™. In some instanceshybrid solvents, meaning mixtures of physical and chemical solvents,have been used. An example is Sulfinol®. However, the use of amine-basedacid gas removal solvents is most common. In any instance, solventextraction is typically accomplished using a large, thick-walledcounter-current contacting tower.

The solvent extraction method uses a water-based solvent to absorb theundesirable species. As a consequence, the treated gas retains waterthat again must be removed to avoid subsequent freezing and plugging ofthe liquefaction equipment.

Whether water is removed before or after acid gas separation, the waterremoval process is typically done in several stages to meet theextremely low water content requirement on the gas to be liquefied. Aprocess under development is based on a glycol dehydration system forbulk water removal, followed by several molecular-sieve beds aspolishing stages. Thus, several pieces of large and heavy equipmentwhich are sensitive to motion are required for the solvent extractionstep. Such equipment is unattractive for offshore applications wherespace and weight are a premium and wave motions are unavoidable.

In addition to water, nitrogen may also be removed from the gas stream.Nitrogen should be removed as it contains no heating value and,accordingly, adversely affects the fuel quality. Nitrogen is typicallyremoved after both acid gas removal and liquefaction have occurred.Nitrogen is removed using a distillation column known as a nitrogenrejection unit, or NRU. The NRU is sensitive to wave motions. Further, aNRU typically involves several large and heavy items of heat exchangeequipment which are not particularly suitable for offshore applications.

Other adverse impacts exist from the presence of nitrogen in a raw gasstream. For example, removing the nitrogen after, rather than before,the liquefaction step increases the liquefaction power requirement forthe gas. In this respect, nitrogen increases the amount of gas that mustbe liquefied. Further, the presence of nitrogen lowers the liquefactiontemperature of the mixture since nitrogen has a lower boilingtemperature than methane.

Because of the stringent specifications for the LNG, feed pretreatmentfacilities are large, heavy, and costly. For example, in one floatingLNG concept with nominal levels of contaminants (e.g., water saturation,1% CO₂, 4% N₂) in the inlet gas, facilities to remove those contaminantsrepresent approximately 20% of the total topside facilities weight. Fordevelopments with high levels of inlet gas contaminants (e.g., watersaturation plus 50% to 70% CO₂ and H₂S content), the contaminant removalfacilities can represent greater than 50% of topside facilities weight.Furthermore, the large vertical pressure vessels or towers that aretypically used for contaminant removal may have an undesirable affect onthe stability of a floating structure.

Therefore, a need exists for an improved facility for processing naturalgas for liquefaction that is less sensitive to wave motions and that haslittle affect on the stability of a floating structure. Further, a needexists for a more compact, lightweight, and lower-horsepower LNG systemthat may be employed on an offshore platform. Still further, a needexists for a method of efficiently processing natural gas forliquefaction that is compatible with a high pressure expander cyclerefrigeration system.

BRIEF SUMMARY OF THE INVENTION

A gas processing facility for the liquefaction of a natural gas feedstream is first provided. The facility is designed to be more compactand more efficient than conventional LNG facilities. Therefore, thefacility offered herein is ideally suited for LNG facilities that areoffshore or are located in remote locations. For example, the gasprocessing facility may be located on a floating platform or agravity-based platform offshore.

The facility first comprises a gas separation unit having has at leastone fractionation vessel. The fractionation vessel serves to separatecontaminants from methane gas. To this end, each vessel has a gas inletfor receiving a natural gas mixture. Further, in one embodiment eachvessel includes an adsorbent material that has a kinetic selectivity forcontaminants over methane greater than 5. In this way, the contaminantsbecome kinetically adsorbed within the adsorbent material. Further, eachvessel includes a gas outlet. The gas outlet releases a methane-rich gasstream.

The vessel employs one or more adsorbent beds for adsorptive kineticseparation. The adsorbent beds release the methane-rich gas feed stream.In one aspect, a single vessel having a plurality of adsorbent beds inseries is used. For example, the at least one fractionation vessel inthe gas separation unit may be a vessel containing a plurality ofadsorbent beds in series, such that:

a first adsorption bed is designed to primarily remove water and otherliquid components from the dehydrated natural gas feed stream;

a second adsorption bed is designed to primarily remove a desiccant fromthe dehydrated natural gas feed stream; and

a third vessel comprises an adsorption bed primarily for the removal ofa sour gas component from the dehydrated natural gas feed stream.

Additional vessels may be added to adsorb and separate nitrogen anddifferent sour gases.

In another aspect, multiple vessels in series are employed, with eachvessel releasing a progressively sweeter methane gas stream. Forexample,

a first vessel uses an adsorption bed designed for the removal of waterremaining in a dehydrated natural gas feed stream;

a second vessel uses an adsorption bed designed for the removal of adesiccant from the dehydrated natural gas feed stream; and

a third vessel use an adsorption bed designed for the removal of a sourgas component from the dehydrated natural gas feed stream.

The sour gas component may be one or more sulfurous components.Alternatively, the sour gas component may be carbon dioxide.

The at least one fractionation vessel in the gas separation unitoperates on pressure swing adsorption (PSA) or on rapid cycle pressureswing adsorption (RCPSA). The at least one fractionation vessel mayfurther operate on temperature swing adsorption (TSA) or rapid cycletemperature swing adsorption (RCTSA). In any arrangement, thefractionation vessels are configured to adsorb CO₂, H₂S, H₂O, heavyhydrocarbons, VOC's, mercaptans, or combinations thereof.

The facility also includes a high-pressure expander cycle refrigerationsystem. The refrigeration system includes a first compression unit. Thefirst compression unit is configured to receive a substantial portion ofthe methane-rich gas stream from the gas separation unit, and tocompress the methane-rich gas stream to greater than about 1,000 psia(6,895 kPa). In this way, a compressed gas feed stream is provided.

The refrigeration system also chills the methane-rich gas feed stream inone or more coolers, and then expands the chilled gas feed stream toform a liquefied product stream. To this end, the system includes afirst cooler configured to cool the compressed gas feed stream to form acompressed, cooled gaseous feed stream, and a first expander configuredto expand the cooled, compressed, gaseous feed stream to form a productstream.

The product stream has a liquid fraction and a small remaining vaporfraction. Preferably, the gas processing facility also includes a liquidseparation vessel. The separation vessel is configured to separate theliquid fraction and the remaining vapor fraction. The vapor fraction isstill very cold and may be captured as a flash gas and circulated aspart of a first refrigeration loop. The first refrigeration loop willhave at least one heat exchanger that serves as the first cooler. Thefirst cooler will receive the vapor fraction from the first expander,and release (i) the compressed, cooled gaseous feed stream and (ii) apartially-warmed vapor stream after heat-exchanging with the compressedgas feed stream.

The high-pressure expander cycle refrigeration system may include aseparate heat exchanger that is configured to further cool thecompressed gas feed stream. This is done at least partially by indirectheat exchange between a refrigerant stream (along with a portion of thevapor stream) and the compressed, methane-rich gas feed stream. Theseparate heat exchanger is a second cooler. The refrigeration systemwill then also include a second refrigeration loop having (i) a secondcompression unit configured to re-compress the refrigerant stream afterthe refrigerant stream passes through the second cooler, and (ii) asecond expander configured to receive the compressed refrigerant streamfrom the second cooler, and expand the compressed refrigerant streamprior to returning it to the second cooler.

The second cooler may sub-cool the chilled gas feed stream after thechilled gas feed stream leaves the first cooler. Alternatively and morepreferably, the second cooler pre-cools the compressed gas feed streambefore the compressed gas feed stream enters the first cooler. To dothis, the second cooler receives the partially-warmed vapor stream fromthe first cooler for further heat-exchanging with the compressed gasfeed stream, and releases a warmed vapor product stream to a thirdcompression unit to complete the first refrigeration loop.

In any event, the first refrigeration loop preferably cycles the vaporportion of the product back to the first compression unit. To do this,the first refrigeration loop may include a third compression unit forcompressing the partially-warmed vapor stream after heat-exchanging withthe compressed gas feed stream, and a line for merging the compressed,partially-warmed vapor stream with the compressed methane-rich gas feedstream. This completes the first refrigeration loop.

The gas processing facility preferably further comprises a dehydrationvessel. The dehydration vessel is configured to receive the natural gasfeed stream and remove a substantial portion of water from the naturalgas feed stream. The dehydration unit then releases a dehydrated naturalgas feed stream to the gas separation unit.

A process for liquefying a natural gas feed stream is also providedherein. The process employs adsorptive kinetic separation to produce amethane-rich gas stream. The process then further utilizes ahigh-pressure expander cycle refrigeration system to chill the methaneand to provide an LNG product. The LNG product is preferably generatedon a floating platform or a gravity-based platform offshore.

The process first includes receiving the natural gas feed stream at agas separation unit. The gas separation unit has at least onefractionation vessel. The fractionation vessels are designed inaccordance with the fraction vessel described above in its variousembodiments. The fractionation vessels preferably operate on pressureswing adsorption (PSA) or rapid cycle pressure swing adsorption (RCPSA)to regenerate a series of adsorption beds. The adsorption beds aredesigned to adsorb CO₂, H₂S, H₂O, heavy hydrocarbons, VOC's, mercaptans,nitrogen, or combinations thereof.

The process also includes substantially separating methane fromcontaminants within the natural gas feed stream. This is done throughthe use of adsorption beds in the one or more fractionation vessels. Asa result, the process also includes releasing a methane-rich gas streamfrom the gas separation unit. In one aspect, separating methane fromcontaminants is conducted through the gas separation unit at a pressureof at least about 500 pounds per square inch absolute (psia).

The process next comprises directing the methane-rich gas stream into ahigh-pressure expander cycle refrigeration system. The refrigerationsystem is generally designed in accordance with the refrigeration systemdescribed above in its various embodiments. Thus, the refrigerationsystem preferably includes a first refrigeration loop for cycling thevapor portion of the product for use as a coolant in a first cooler, anda second refrigeration loop for cycling a nitrogen-containing gas as arefrigerant in a second cooler.

The process also includes compressing the methane-rich gas stream. Thegas stream is compressed to a pressure that is greater than about 1,000psia (6,895 kPa) in order to form a compressed gas feed stream. Theprocess then comprises cooling the compressed gas feed stream throughthe second and first coolers to form a compressed, cooled gaseous feedstream.

The process also includes expanding the cooled, compressed, gaseous feedstream. This forms the LNG product stream having a liquid fraction and aremaining vapor fraction.

The high-pressure expander cycle refrigeration system preferablyincludes a liquid separation vessel. The process then further comprisesseparating the liquid fraction and the remaining vapor fraction.

A method for liquefying a natural gas feed stream is also providedherein. As with the process described above, the method employsadsorptive kinetic separation to produce a methane-rich gas stream. Themethod then further utilizes a high-pressure expander cyclerefrigeration system to chill the methane and to provide an LNG product.The LNG product is preferably generated on a floating platform or agravity-based platform offshore.

The method first includes receiving the natural gas feed stream at a gasprocessing facility. The gas processing facility will include adehydration vessel. The method then includes passing the natural gasfeed stream through a dehydration vessel. This serves to remove asubstantial portion of water from the natural gas feed stream. Adehydrated natural gas feed stream is then released to a gas separationunit as a dehydrated natural gas feed stream.

The gas separation unit has at least one fractionation vessel. Thefractionation vessels are designed in accordance with the fractionvessel described above in its various embodiments. The fractionationvessels preferably operate on pressure swing adsorption (PSA) or rapidcycle pressure swing adsorption (RCPSA) to regenerate a series ofadsorption beds.

The method next comprises passing the dehydrated natural gas feed streamthrough the series of adsorbent beds. This serves to separate methanegas from contaminants in the dehydrated natural gas feed stream. Thebeds use adsorptive kinetic separation. The adsorption beds are designedto adsorb CO₂, H₂S, H₂O, heavy hydrocarbons, VOC's, mercaptans,nitrogen, or combinations thereof.

In one aspect, a single vessel having a plurality of adsorbent bedsaligned in series is used.

In another aspect, multiple vessels in series are employed, with thevessels being aligned in series with the flow of the dehydrated naturalgas feed stream. Each vessel releases a progressively sweeter methanegas stream.

As a result of passing the dehydrated natural gas feed stream throughthe adsorbent beds, a methane-rich gas stream is produced. The methodcomprises releasing the methane-rich gas stream from the gas separationunit. The methane-rich gas stream is then directed into a high-pressureexpander cycle refrigeration system.

The refrigeration system is generally designed in accordance with therefrigeration system described above in its various embodiments. Thus,the refrigeration system preferably includes a first refrigeration loopfor cycling the vapor portion of the product for use as a coolant in afirst cooler, and a second refrigeration loop for cycling anitrogen-containing gas as a refrigerant in a second cooler.

The method also includes compressing the methane-rich gas stream. Thegas stream is compressed to a pressure that is greater than about 1,000psia (6,895 kPa) in order to form a compressed gas feed stream. Theprocess then comprises cooling the compressed gas feed stream to form acompressed, cooled gaseous feed stream.

The method further includes expanding the cooled, compressed, gaseousfeed stream. This forms the LNG product stream having a liquid fractionand a small remaining vapor fraction. In one aspect, expanding thecooled, compressed, gaseous feed stream comprises reducing the pressureof the cooled, compressed, gaseous feed stream to a pressure betweenabout 50 psia (345 kPa) and 450 psia (3,103 kPa).

BRIEF DESCRIPTION OF THE DRAWINGS

So that the present inventions can be better understood, certainillustrations, charts and/or flow charts are appended hereto. It is tobe noted, however, that the drawings illustrate only selectedembodiments of the inventions and are therefore not to be consideredlimiting of scope, for the inventions may admit to other equallyeffective embodiments and applications.

FIG. 1 is a schematic flow diagram of a facility for producing LNG, inaccordance with one embodiment herein. The facility includes a gasseparation unit that produces a methane-rich gas stream, and ahigh-pressure expander cycle refrigeration system for generating an LNGproduct.

FIG. 2 is a perspective view of a pressure swing adsorption vessel asmay be used in the facility of FIG. 1, in one embodiment. The vesselalso represents a kinetic fractionator of the present inventions, in oneembodiment.

FIG. 3A is a perspective view of the adsorbent bed and flow channels forthe pressure swing adsorption vessel of FIG. 2, in one embodiment. Majorflow channels are seen between adsorbent rods along a major axis of theadsorbent bed.

FIG. 3B provides an exploded view of the adsorbent bed of FIG. 3A. FIG.3B provides an exposed view of the optional second gas outlet. Atransverse flow channel is shown extending into the vessel, serving as aminor flow channel.

FIG. 3C is a longitudinal, cross-sectional view of the adsorbent bed ofFIG. 3A, in an alternate embodiment. The view is taken across line C-Cof FIG. 3A. Here, a series of stepped surfaces are seen along theadsorbent rods, which serve as minor flow channels.

FIG. 4 is a perspective view of the adsorbent bed and flow channels forthe pressure swing adsorption vessel of FIG. 2, in a modifiedarrangement. Major flow channels are seen between adsorbent rods along amajor axis of the adsorbent bed. Transverse flow channels are seen inexploded-away portions of the adsorbent bed, which serve as minor flowchannels.

FIG. 5 is a schematic flow diagram of a high-pressure expander cyclerefrigeration system, in one embodiment. The refrigeration systemreceives a methane-rich gas stream, and generates an LNG product. Theillustrative refrigeration system employs a secondary cooling loop thatis a closed loop using nitrogen gas, or a nitrogen-rich gas, or aportion of the methane-rich gas stream from the gas separation unit.

FIG. 6 is a flow chart showing steps for liquefying a raw natural gasstream.

FIG. 7 is a flowchart showing steps for separating contaminants from theraw natural gas stream using adsorptive kinetic separation.

DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS Definitions

As used herein, the term “hydrocarbon” refers to an organic compoundthat includes primarily, if not exclusively, the elements hydrogen andcarbon. Hydrocarbons generally fall into two classes: aliphatic, orstraight chain hydrocarbons, and cyclic, or closed ring hydrocarbons,including cyclic terpenes. Examples of hydrocarbon-containing materialsinclude any form of natural gas, oil, coal, and bitumen that can be usedas a fuel or upgraded into a fuel.

As used herein, the term “fluid” refers to gases, liquids, andcombinations of gases and liquids, as well as to combinations of gasesand solids, and combinations of liquids and solids.

As used herein, the term “hydrocarbon fluids” refers to a hydrocarbon ormixtures of hydrocarbons that are gases or liquids. For example,hydrocarbon fluids may include a hydrocarbon or mixtures of hydrocarbonsthat are gases or liquids at formation conditions, at processingconditions, or at ambient conditions (15° C. and 1 atm pressure).Hydrocarbon fluids may include, for example, oil, natural gas, coal bedmethane, shale oil, pyrolysis oil, pyrolysis gas, a pyrolysis product ofcoal, and other hydrocarbons that are in a gaseous or liquid state.

As used herein, an “acid gas” means any gas that dissolves in waterproducing an acidic solution. Non-limiting examples of acid gasesinclude hydrogen sulfide (H₂S), carbon dioxide (CO₂), sulfur dioxide(SO₂), carbon disulfide (CS₂), carbonyl sulfide (COS), mercaptans, ormixtures thereof.

As used herein, the term “subsurface” refers to geologic strataoccurring below the earth's surface.

The term “seabed” refers to the floor of a marine environment. Themarine environment may be an ocean or sea or any other body of waterthat experiences waves, winds, and/or currents.

The term “marine environment” refers to any offshore location. Theoffshore location may be in shallow waters or in deep waters. The marineenvironment may be an ocean body, a bay, a large lake, an estuary, asea, or a channel.

The term “about” is intended to allow some leeway in mathematicalexactness to account for tolerances that are acceptable in the trade.Accordingly, any small deviations upward or downward from the valuemodified by the term “about” should be considered to be explicitlywithin the scope of the stated value.

The term “swing adsorption process” includes processes such as pressureswing adsorption (PSA), thermal swing adsorption (TSA), and partialpressure swing or displacement purge adsorption (PPSA), includingcombinations of these processes. These swing adsorption processes can beconducted with rapid cycles, in which case they are referred to as rapidcycle pressure swing adsorption (RCPSA), rapid cycle thermal swingadsorption (RCTSA), and rapid cycle partial pressure swing ordisplacement purge adsorption (RCPPSA). The term swing adsorption alsoincludes these rapid cycle processes.

As used herein, the term “pressure swing adsorption” shall be taken toinclude all of the processes, i.e., PSA, PPSA, RCPSA, and RCPPSA,including combinations of these processes, that employ a change inpressure for a purge cycle.

As used herein, the term “wellbore” refers to a hole in the subsurfacemade by drilling or insertion of a conduit into the subsurface. Awellbore may have a substantially circular cross section, or othercross-sectional shapes. As used herein, the term “well,” when referringto an opening in the formation, may be used interchangeably with theterm “wellbore.”

The term “platform” means any platform or surface dimensioned andconfigured to receive fluid processing equipment.

DESCRIPTION OF SPECIFIC EMBODIMENTS

FIG. 1 is a schematic diagram of a gas processing facility 100 forproducing LNG in accordance with one embodiment herein. The “LNG” isnatural gas that has been liquefied through a cooling process. The gasprocessing facility 100 operates to receive raw natural gas, removecertain undesirable components in order to produce a “sweetened” gasstream that meets established specifications, and then chill thesweetened (“methane-rich”) gas stream into a substantially liquid phasefor ready transport.

In the illustrative arrangement of FIG. 1, the facility 100 receivesproduction fluids from a reservoir. A reservoir is shown schematicallyat 110. The reservoir 110 represents a subsurface formation thatcontains hydrocarbon fluids in commercially acceptable quantities. Thehydrocarbon fluids exist in situ in primarily a gaseous phase.

The production fluids are produced through a plurality of wellbores. Asingle illustrative wellbore 112 is indicated in FIG. 1. However, it isunderstood that numerous wellbores 112 will be drilled through the earthsurface and into the subsurface reservoir 110. The present inventionsare not limited by the number of wellbores or the manner in whichwellbore completions are made.

The wellbore 112 transports hydrocarbon fluids from the reservoir 110and to an earth surface 115. The earth surface 115 may be on land. Morepreferably for the present inventions, the earth surface 115 is aseabed. In this latter instance, wellheads (not shown) are placed alongthe bottom of a marine environment. Subsea jumpers and/or flowlines willdirect production fluids to a manifold (not shown), which then deliversfluids to an ocean surface via one or more production risers.

In FIG. 1, line 112′ is shown transporting hydrocarbon fluids. Line 112′may be a flow line on land. More preferably, line 112′ is representativeof a production riser within a marine environment. In either instance,the production fluids are delivered to a separator 120.

Upon arrival at the separator 120, the production fluids represent a rawnatural gas mixture. The production fluids contain methane, or naturalgas. The production fluids may also contain so-called “heavyhydrocarbons,” representing ethane and, possibly, propane. Most likely,the production fluids will also contain water (or brine), along withnitrogen. Also, the production fluids may contain hydrogen sulfide,carbon dioxide, and other so-called “sour gas” components. Finally, theproduction fluids may contain benzene, toluene, or other organiccompounds.

The separator 120 provides a general separation of liquids from gases.This is typically done at production pressure. The separator 120 may bea gravity separator having thick steel walls. The separator 120 servesto filter out impurities such as brine and drilling fluids. It may alsoremove at least a portion of any condensed hydrocarbons. Some particlefiltration may also take place.

More preferably, the separator 120 serves as a dehydration vessel. Thedehydration vessel uses a desiccant such as ethylene glycol in order toabsorb water and release gas-phase fluids. Liquids are released from thebottom of the separator 120, while gases are released at the top.

In FIG. 1, line 121 represents a liquid line. The fluids in line 121 areprimarily water, with possibly some heavy hydrocarbons. The heavyhydrocarbons in line 121 will be a small amount of ethane and, perhaps,a bit of propane and butane. Additional separation may take placethrough gravity separation, heat treatment, or other means known in theart to capture the valuable liquid hydrocarbons.

Line 122 represents a gas line. The fluids in line 122 are primarilymethane, with some ethane and other “heavy hydrocarbons” as well. Inaddition, the fluids in line 122 will have contaminants. These mayinclude “sour” components such as hydrogen sulfide and carbon dioxide.These may also include water in vapor form. Further, the contaminantsmay include nitrogen. Certain metal contaminants may be suspended in thevapor, such as arsenic, cobalt, molybdenum, mercury, or nickel. Finally,trace organic compounds such as benzene, toluene, or xylene, may bepresent.

It is desirable to separate the various components so that a fluidstream comprising substantially methane is produced. For internationalsales, LNG specifications may require that natural gas have thefollowing content:

TABLE 1 Pretreatment LNG Specifications Component Feed Specification CO₂<50 ppmv H₂O <0.5 ppmv H₂S <3.5 ppm Total S <20 mg/Nm³ Hg <μg/Nm³ C₅+<0.1 mol. % C₆H₆ <1 ppmv

In order to achieve the LNG specifications of Table 1, gas treatmentmust take place. In FIG. 1, a gas separation unit 130 is schematicallyshown. The gas separation unit 130 may also be referred to as aSelective Component Removal System, or “SCRS.” The gas separation unit130 utilizes a series of adsorbent beds using Adsorptive KineticSeparation, or “AKS.”

AKS is a process that employs a relatively new class of solid adsorbentsthat rely upon the rate at which certain species are adsorbed onto astructured material relative to other species. The structured materialis sometimes referred to as an absorbent bed. Adsorbent beds operate onthe principle that different molecules can have different affinities foradsorption. This provides a mechanism for the adsorbent to discriminatebetween different gasses and, therefore, to provide separation.

In order to effectuate the separation, adsorbent beds employ a highlyporous microstructure. Selected gas molecules become attached to thesurface area provided along the pores. The gas adsorbed onto theinterior surfaces of the micro-porous material may consist of a layeronly a few molecules in thickness. The micro-porous material may havealso surface areas of several hundred square meters per gram. Suchspecifications enable the adsorption of a significant portion of theadsorbent's weight in gas.

Different types of adsorbent beds are known. Typical adsorbents includeactivated carbons, silica gels, aluminas, and zeolites. In some cases, apolymeric material can be used as the adsorbent material. In anyinstance, the adsorbent bed preferentially adsorbs a more readilyadsorbed component (known as the “heavy” gas) relative to a less readilyadsorbed component (known as the “light” gas) of the gas mixture.

In addition to their affinity for different gases, zeolites and sometypes of activated carbons, called carbon molecular sieves, may utilizetheir molecular sieve characteristics to exclude or slow the diffusionof some gas molecules into their structure. This provides a mechanismfor selective adsorption based on the size of the molecules. In thisinstance, the adsorbent bed restricts the ability of larger molecules tobe adsorbed, thus allowing the gas to selectively fill the micro-porousstructure of an adsorbent material with one or more species from amulti-component gas mixture.

Different adsorption techniques for gas separation are known. Oneadsorption technique is pressure swing adsorption, or “PSA.” PSAprocesses rely on the fact that, under pressure, gaseous contaminantstend to be adsorbed within the pore structure of an adsorbent material,or within the free volume of a polymeric material, to different extents.The higher the pressure in the adsorption vessel, the more gas isadsorbed. In the case of natural gas, the natural gas mixture may bepassed under pressure through an adsorption vessel. The pores of thepolymeric or micro-porous adsorbent become filled with hydrogen sulfideand carbon dioxide to a greater extent than with methane. Thus, most oreven all of the H₂S and CO₂ will stay in the sorbent bed, while the gascoming out of the vessel will be enriched in methane. Any remainingwater and possibly some heavy hydrocarbons will also be retained asadsorbents. In addition, any benzene, toluene, or other volatile organiccompounds will be retained as adsorbents.

The pressure swing adsorption system may be a rapid cycle pressure swingadsorption system. In the so-called “rapid cycle” processes, cycle timescan be as small as a few seconds. A rapid cycle PSA (“RCPSA”) unit canbe particularly advantageous, as such a unit is compact relative tonormal PSA devices. Further, RCPSA contactors can enable a significantincrease in process intensification (e.g., higher operating frequenciesand gas flow velocities) when compared to conventional PSA.

When the adsorbent bed reaches the end of its capacity to adsorbcontaminants, it can be regenerated by reducing the pressure. Thiscauses the vessel to release the adsorbed components. A concentratedcontaminant stream is thus released separate from the methane gasstream. In this way, the adsorption bed may be regenerated forsubsequent re-use.

In most PSA cases, reducing the pressure in the pressurized chamber downto ambient pressure will cause a majority of the hydrogen sulfide andother contaminants to be released from the adsorbent bed. In some cases,the pressure swing adsorption system may be aided by the use of a vacuumchamber to apply sub-ambient pressure to the concentrated contaminantstream. In the presence of lower pressure, sulfurous components, carbondioxide, and heavy hydrocarbons will more completely desorb from thesolid matrix making up the adsorbent bed.

A related gas separation technique is temperature swing adsorption, or“TSA.” TSA processes also rely on the fact that, under pressure, gasestend to be adsorbed within the pore structure of micro-porous adsorbentmaterials or within the free volume of a polymeric material, todifferent extents. When the temperature of the adsorbent bed in thevessel is increased, the adsorbed gas molecules are released, orde-sorbed. This is done in a regeneration heater that employs a heateddry gas. The dry gas comprises primarily methane, but may also includenitrogen and helium. By cyclically swinging the temperature of adsorbentbeds within a vessel, TSA processes can be used to separate gases in amixture.

When a TSA process is used, a set of valves may be provided to pulse theflow of heating or cooling fluids that enter and leave the vessel. Anelectric heating or cooling jacket may also be used to producetemperature swings. Optionally, the swing adsorption unit uses a partialpressure purge displacement process. In this case, a valve or set ofvalves is provided to pulse the flow of the purge displacement streaminto the adsorption bed. The adsorption bed is contained within apressure vessel. Optionally, this vessel and the associated valving iscontained within a secondary pressure vessel. This secondary pressurevessel is designed to mitigate the significance of leaks through sealsin the valves inside the swing adsorption unit. This can be especiallyimportant when rotary valves are used.

A combination of pressure swing regeneration and thermal swingregeneration may be employed. In either instance, the gas treatingfacility 130 employs a series of absorbent beds, each designed to retainone or more components while releasing the remainder of the gas stream.

The adsorptive material or “bed” is maintained in a pressure vessel.FIG. 2 provides a perspective view of an illustrative pressure swingadsorption vessel 200. The vessel 200 operates for the purpose ofreceiving a natural gas mixture, and separating the mixture into atleast two components.

The vessel 200 defines an elongated, pressure-containing body. Thevessel 200 includes a housing 205. Preferably, the housing 205 isfabricated from iron or steel. In the arrangement of FIG. 2, the vessel200 rests along a surface 201 in a substantially horizontal orientation.However, the vessel 200 may alternatively be operated in a verticalorientation. In either instance, the vessel 200 may include varioussupporting legs or pads 215.

The vessel 200 is able to operate at high pressures so as to accommodatethe inlet pressures experienced with the processing of natural gas. Forexample, such inlet pressures may exceed 200 psig, and more frequentlymay be greater than about 1,000 psig. This allows the vessel 200 tooperate at or close to reservoir pressure. To monitor internal pressure,the vessel 200 includes gauges or other pressure-monitoring devices. Arepresentative gauge is shown at 250 in FIG. 2. Of course, it isunderstood that modern pressure-monitoring devices operate primarily asdigital systems that interact with valves, clocks, and operationalcontrol software.

The vessel 200 has a first end shown at 202, and a second end shown at204. A gas inlet 210 is provided at the first end 202, while a first gasoutlet 230 is provided at the second end 204. Optionally, a second gasoutlet 220 is provided intermediate the first end 202 and the second end204, or intermediate the gas inlet 210 and the first gas outlet 230.

In operation, the vessel 200 serves as a kinetic fractionator, oradsorbent contactor. A natural gas mixture, or feed stream, isintroduced into the vessel 200 through the gas inlet 210. Arrow “I”indicates the flow of fluid into the vessel 200. The natural gas iscontacted within the vessel 200 by an adsorbent bed (not shown in FIG.2). The adsorbent bed uses kinetic adsorption to capture contaminants.At the same time, the adsorbent bed releases a methane-rich gas streamthrough the first gas outlet 230. Flow of the methane-rich gas streamfrom the vessel 200 is indicated at arrow O₁.

It is understood that the vessel 200 is part of the larger gasseparation unit 130. The gas separation unit 130 includes valving,vessels, and gauges as needed to carry out regeneration of the adsorbentbed within the vessel 200 and the capture of the separated gascomponents. Further, where rapid cycle PSA is employed, the vessel willinclude rotary valving with a rotating manifold for rapidly cycling anatural gas mixture. In this respect, rapid cycle pressure swingadsorption (RCPSA) vessels can be constructed with a rotary valvingsystem to facilitate the flow of gas through a rotary adsorber modulethat contains a number of separate adsorbent bed compartments or“tubes,” each of which is successively cycled through the sorption anddesorption steps as the rotary module completes the cycles of operation.

A rotary adsorber module is normally comprised of multiple tubes heldbetween two seal plates on either end of the rotary adsorber modulewherein the seal plates are in contact with a stator comprised ofseparate manifolds. The inlet gas is conducted to the RCPSA tubes andthe processed purified product gas and the tail retentate gas exitingthe RCPSA tubes are conducted away from the rotary adsorber module. Bysuitable arrangement of the seal plates and manifolds, a number ofindividual compartments or tubes may pass through the characteristicsteps of the complete cycle at any given time. In contrast, withconventional PSA, the flow and pressure variations, required for theRCPSA sorption/desorption cycle, changes in a number of separateincrements on the order of seconds per cycle, which smoothes out thepressure and flow rate pulsations encountered by the compression andvalving machinery. In this form, the RCPSA module includes valvingelements angularly spaced around the circular path taken by the rotatingsorption module so that each compartment is successively passed to a gasflow path in the appropriate direction and pressure to achieve one ofthe incremental pressure/flow direction steps in the complete RCPSAcycle.

In any arrangement, the vessel 200 utilizes an adsorbent bed to capturecontaminants on the surface of a micro-porous adsorbent material andalong the pore spaces therein. FIG. 3A is a perspective view of anadsorbent bed 300, in one embodiment. Here, the illustrative adsorbentbed 300 has an annular adsorbent ring 305. The adsorbent ring 305 isdimensioned to fit along an inner diameter of the housing 205 of thevessel 200.

Within the adsorbent ring 305 is a plurality of adsorbent rods 315. Theadsorbent rods 315 run substantially along the length of the adsorbentbed 300. This means that the rods 315 run essentially from the first end302 to the second end 304 of the vessel 300. The adsorbent ring 305 andthe adsorbent rods 315 are fabricated from a material thatpreferentially adsorbs an undesirable gas. The undesirable gas may bewater vapor, CO₂, H₂S, mercaptans, heavy hydrocarbons in gaseous phase,or combinations thereof.

The adsorbent material is preferably selected from the 8-ring zeoliteshaving a Si:Al ratio from about 1:1 to about 1000:1, or preferably fromabout 10:1 to about 500:1, or more preferably from about 50:1 to about300:1. The term “Si:Al ratio” as used herein means the molar ratio ofsilica to alumina of the zeolite structure. The more preferred 8-ringzeolites for the capture of sour gas include DDR, Sigma-1 and ZSM-58.Zeolite materials having appropriate pore sizes for the removal of heavyhydrocarbons include MFI, faujasite, MCM-41, and Beta. It is preferredthat the Si:Al ratio of zeolites utilized for heavy hydrocarbon removalbe from about 20:1 to about 1,000:1, and preferably from about 200:1 toabout 1,000:1 in order to prevent excessive fouling of the adsorbent.

The zeolite may be present in the adsorbent ring 305 and the adsorbentrods 315 in any suitable form. For example, zeolite material may be inthe form of beads that are packed to form the adsorbent material.Adsorbent beads, or aggregates, for swing adsorption processes are knownin the art and can be of any suitable shape, including spherical orirregular. Adsorbent aggregates may be formed by adhering micro-porouszeolite crystals together with binder materials. The micro-pores existdue to the crystalline structure of the zeolite, in this case,preferably 8-ring zeolites. The binder material is typically a densematerial that does not have adsorptive properties, but which is used tobind the zeolite crystals. In order to function effectively, the size ofbinder particles must be smaller than the size of the individual zeolitecrystals.

In one embodiment of the adsorbent bed 300, a magnetic material may beincorporated into the adsorbent rods 315. For example, each rod 315 mayhave an inner bore, and a magnetic material may be placed along theinner bore. The rods 315 may then be subjected to a magnetic or anelectromagnetic field during packing. The magnetic field causes the rods315 to repel one another, thereby assuring uniform spacing between therods 315. Uniform packing of rods 315 is particularly important forkinetic and fast cycled adsorption processes so that gas components arenot preferentially driven through one flow channel 310 over another.Application of the magnetic field may further provide for a homogeneousorientation of the zeolite material. Optionally, the magnetic field maybe applied during the cycles themselves.

Referring again to FIG. 3, within the annular adsorbent ring 305 andbetween the adsorbent rods 315 is a plurality of flow channels. The flowchannels are seen at 310. The flow channels 310 define major flowchannels that flow along a major axis of the adsorbent bed 300.

The flow channels 310 create a type of structured adsorbent contactorreferred to as a “parallel channel contactor.” Parallel channelcontactors are a subset of adsorbent contactors comprising structured(engineered) adsorbents in which substantially parallel flow channelsare incorporated into the adsorbent structure. The flow channels 310 maybe formed by a variety of means, some of which are described in U.S.Pat. Publ. No. 2008/0282887 titled “Removal of CO₂, N₂, and H₂S from GasMixtures Containing Same,” incorporated herein by reference.

The adsorbent material forming the annular ring 305 and the rods 315 hasa “kinetic selectivity” for two or more gas components. As used herein,the term “kinetic selectivity” is defined as the ratio of singlecomponent diffusion coefficients, D (in m²/sec), for two differentspecies. The single component diffusion coefficients are also known asthe Stefan-Maxwell transport diffusion coefficients that are measuredfor a given adsorbent for a given pure gas component. Therefore, forexample, the kinetic selectivity for a particular adsorbent for acomponent A with respect to a component B would be equal to D_(A)/D_(B).

The single component diffusion coefficients for a material can bedetermined by tests known in the adsorptive materials art. The preferredway to measure the kinetic diffusion coefficient is with a frequencyresponse technique described by Reyes, et al. in “Frequency ModulationMethods for Diffusion and Adsorption Measurements in Porous Solids,” J.Phys. Chem. B. 101, pages 614-622 (1997), which is incorporated hereinby reference. In the kinetically controlled separation for the vessel200, it is preferred that kinetic selectivity (i.e., D_(A)/D_(B)) of theselected adsorbent for the first component (e.g., CO₂) with respect tothe second component (e.g., methane) be greater than 5.

The term “selectivity” as used herein is based on a binary comparison ofthe molar concentration of components in the feed stream and the totalnumber of moles of these components adsorbed by the particular adsorbentduring the adsorption step of the process cycle under the specificsystem operating conditions and feed stream composition. For a feed gasstream containing a component A, a component B, and optionallyadditional components, an adsorbent that has a greater “selectivity” forcomponent A than component B will have at the end of the adsorption stepof the swing adsorption process cycle a ratio:

U _(A)=(total moles of A in the adsorbent)/(molar concentration of A inthe feed)

that is greater than the ratio:

U _(B)=(total moles of B in the adsorbent)/(molar concentration of B inthe feed)

where: U_(A) is the “Adsorption Uptake of component A,” and

U_(B) is the “Adsorption Uptake of component B.”

Therefore, for an adsorbent having a selectivity for component A overcomponent B that is greater than one:

Selectivity=U _(A) /U _(B) (where U _(A) >U _(B)).

Amongst a comparison of different components in a natural gas feedstream, the component with the smallest ratio of the total moles pickedup in the adsorbent to its molar concentration in the feed stream is thelightest component in the swing adsorption process. The light componentis taken to be the species, or molecular component, that is notpreferentially taken up by the adsorbent in the adsorption process. Thismeans that the molar concentration of the lightest component in thestream coming out during the adsorption step is greater than the molarconcentration of that lightest component in the feed stream. In thepresent disclosure, the adsorbent contactor 200 has a selectivity for afirst component (e.g., CO₂) over a second component (e.g., methane) ofat least 5, more preferably a selectivity for a first component over asecond component of at least 10, and most preferably a selectivity for afirst component over a second component of at least 25.

Note that it is possible to remove two or more contaminantssimultaneously; however, for convenience the component or componentsthat are to be removed by selective adsorption may be referred to hereinas a single contaminant or a heavy component.

Recovery of the light component may also be characterized by relativeflow rate. Thus, recovery of methane may be defined as the time averagedmolar flow rate of the methane in the product stream (shown at O₁ in thefirst outlet 230) divided by the time averaged molar flow rate of themethane in the feed stream (depicted as gas inlet 210). Similarly,recovery of the carbon dioxide and other heavy components is defined asthe time averaged molar flow rate of the heavy components in thecontaminant stream (shown at O₂ in the second gas outlet 220) divided bythe time averaged molar flow rate of the heavy component in the feedstream (depicted as gas inlet 210).

Additional technical information concerning component diffusioncoefficients and kinetic selectivity is provided in co-owned U.S. Pat.Publ. No. 2008/0282887, referenced above.

In order to enhance the efficiency of the gas separation process, minorflow channels may also be provided in the bed 300. The minor flowchannels increase the surface area exposure of the adsorbent materialalong the rods 315.

FIG. 3B provides an exploded view of the adsorbent bed 300 of FIG. 3A.The adsorbent bed 300 is cut across the optional second gas outlet 220.The major flow channels 310 running through the adsorbent bed 300 areagain seen. In addition, a transverse flow channel is seen at 320. Thetransverse flow channel 320 serves as a minor flow channel. The flowchannel 320 is seen partially extending into the adsorbent bed 300.However, the transverse flow channel 320 may optionally extend most ofthe way around the circumference of the annular adsorbent ring 305.

In the arrangement of FIG. 3B, only a single minor flow channel 320 isshown. However, the adsorbent bed 300 may have a plurality of minor flowchannels 320. These may optionally be manifolded together with flowconverging on the second gas outlet 220.

FIG. 3C is a longitudinal, cross-sectional view of the adsorbent bed 300of FIG. 3A. The view is cut through line C-C of FIG. 3A. Longitudinaladsorbent rods 315 are seen in FIG. 3C. In addition, major flow channels310 are visible between the rods 315.

A series of stepped surfaces 325 are seen along the adsorbent rods 315.The stepped surfaces 325 also serve as minor flow channels. In lieu ofstepped surfaces 325, the surfaces 325 may be helical or spiraledsurfaces. In any arrangement, the stepped surfaces 325 may be used inaddition to or in lieu of the transverse channel 320 to increase surfacearea and improve kinetic selectivity without need of large and expensiveheat transfer units.

The major 310 and minor 320, 325 flow channels provide paths in thefractionator 300 through which gas may flow. Generally, the flowchannels 310, 320, 325 provide for relatively low fluid resistancecoupled with relatively high surface area. Flow channel length should besufficient to provide the desired mass transfer zone, which is, atleast, a function of the fluid velocity and the ratio of surface area tochannel volume.

The flow channels 310, 320, 325 are preferably configured to minimizepressure drop in the vessel 200. Thus, tortuous flow paths are minimizedor avoided. If too much pressure drop occurs across the bed 300, thenhigher cycle frequencies, such as on the order of greater than 100 cpm,are not readily achieved. In addition, and as noted above, it ispreferred that the rods 315 be equidistantly spaced so as to create adegree of channel uniformity.

In one aspect, the flow channels 310 are generally divided so that thereis little or no cross-flow. In this instance, a fluid flow fractionentering a channel 310 at the first end 302 of the fractionator 200 doesnot significantly communicate with any other fluid fraction enteringanother channel 310 at the first end 302 until the fractions recombineupon exiting at the second end 304. In this arrangement, the volumes ofthe major flow channels 310 will be substantially equal to ensure thatall of the channels 310 are being fully utilized, and that the masstransfer zone defined by the interior volume of the vessel 200 issubstantially equally contained.

The dimensions of the flow channels 310 can be computed fromconsiderations of pressure drop along the contactor vessel 200. It ispreferred that the flow channels 310 have a channel gap from about 5 toabout 1,000 microns, preferably from about 50 to about 250 microns. Asutilized herein, the “channel gap” of a flow channel 310 is defined asthe length of a line across the minimum dimension of the flow channel310 as viewed orthogonal to the flow path. For instance, if the flowchannel 310 is circular in cross-section, then the channel gap is theinternal diameter of the circle. However, if the channel gap isrectangular in cross-section, the flow gap is the distance of a linebisecting the flow gap from corner to corner.

It should be noted that the major flow channels 310 can be of anycross-sectional configuration or geometric profile. In FIGS. 3A and 3B,the major flow channels 310 are star-shaped. Regardless of the shape, itis preferred that the ratio of the volume of adsorbent material to theflow channel volume in the adsorbent contactor 200 be from about 0.5:1to about 100:1, and more preferably from about 1:1 to about 50:1.

In some pressure swing applications, particularly with RCPSAapplications, the flow channels are formed when adsorbent sheets arelaminated together. The flow channels within the sheets will contain aspacer or mesh that acts as a spacer. However, the spacers take upmuch-needed space so the use of laminated sheets is not preferred.

In lieu of laminated sheets, a plurality of small, transverse minor flowchannels may be machined through the adsorbent rods. FIG. 4 provides aperspective view of an adsorbent bed 400 for the pressure swingadsorption vessel of FIG. 2, in a modified arrangement. The adsorbentbed 400 has an outer surface 405. The outer surface 405 is dimensionedto fit along an inner diameter of the housing 205 of the vessel 200 ofFIG. 2.

Major flow channels 410 are provided within a monolithic adsorbentmaterial 415. The major flow channels 410 are formed along a major axisof the adsorbent bed 400. However, to further increase surface areaalong the adsorbent rods, small transverse channels 420 are formedthrough the monolithic material 415. These channels serve as minor flowchannels 420.

The minor flow channels 420 may be very small tubular channels, having adiameter of less than about 25 microns, for example. The minor flowchannels 420 are not so large as to completely sever an adsorbent rod415. In this way, the need for supporting spacers is avoided.

The optional minor flow channels 420 facilitate pressure balancingbetween the major flow channels 410. Both productivity and gas puritymay suffer if there is excessive channel inconsistency. In this respect,if one flow channel is larger than an adjacent flow channel or receivesmore gas stream than another, premature product break-through may occur.This, in turn, leads to a reduction in the purity of the product gas tounacceptable purity levels. Moreover, devices operating at cyclefrequencies greater than about 50 cycles per minute (cpm) requiregreater flow channel uniformity and less pressure drop than thoseoperating at lower cycles per minute.

Returning now to FIGS. 2 and 3, the vessel 200 in FIG. 2 is shown as acylinder, and the adsorbent rods 315 therein are shown as tubularmembers. However, other shapes may be employed that are suitable for usein swing adsorption process equipment. Non-limiting examples of vesselarrangements include various shaped monoliths having a plurality ofsubstantially parallel channels extending from one end of the monolithto the other; a plurality of tubular members; stacked layers ofadsorbent sheets with spacers between each sheet; multi-layered spiralrolls or bundles of hollow fibers, as well as bundles of substantiallyparallel solid fibers.

In addition, other embodiments for a parallel channel contactor may beemployed. Such embodiments include the contactors shown in and describedin connection with FIGS. 1 through 9 of U.S. Pat. Publ. No.2008/0282887. This publication is again incorporated herein in itsentirety by reference.

Returning to FIG. 1, four illustrative separation stages are shown.These are stage 132′/132″, stage 134, stage 136, and stage 138. Eachstage represents an adsorbent bed, with the stages 132/132″, 134, 136,138 being placed in series. The adsorbent beds preferably each residewithin their own pressure vessel, such as vessel 200 of FIG. 2. However,it is within the scope of the present application for at least some ofthe beds to reside within the same pressure vessel while remaining inseries.

First, stage 132′ represents the removal of water vapor from the gas inline 122. Thus, a first adsorbent bed is provided at stage 132′ whereinthe adsorbent material is designed to adsorb water vapor. Once theadsorbent material is saturated, the bed in stage 132′ is de-sorbed andwater vapor is released through line 131′. Optionally, the water vaporis merged with the liquids line 121 from the separator 120, as indicatedat line 125.

The liquids in line 125 will be predominantly water. These liquids maybe reinjected into the reservoir as part of a water flooding operation.Alternatively, the water may be treated and disposed of in a surroundingmarine environment. Alternatively still, the water may be treated andtaken through a desalinization process for use in irrigation orindustrial use on-shore. Alternatively still, and as noted above, theliquids in line 125 may undergo further separation to capture anyhydrocarbons.

It is preferred that the first stage 132′ simply be a “polishing” stage.This means that most water has already been removed or “knocked out” bya previous dehydration vessel (such as vessel 120, and the adsorbent bedin stage 132′ is simply removing remaining water vapor.

Where a dehydration vessel is used, the fluids in line 122 will includea desiccant such as ethylene glycol. Therefore, an ancillary first stage132″ is provided for desiccant removal. In FIG. 1, desiccant is removedfrom the gas separation unit 130 through a separate adsorption bed. Oncethe bed has become saturated, the desiccant is released through line131″. The desiccant may be recycled for use in the dehydration vessel120.

FIG. 1 also shows a second stage of contaminant removal at 134. Theillustrative second stage 134 is for the removal of heavy hydrocarbons.As noted, heavy hydrocarbons will primarily include any ethane from theoriginal gas stream. Some propane and butane may also be adsorbed. Theheavy hydrocarbons are adsorbed onto the adsorbent bed, while sour gasand lighter hydrocarbons are released.

It is possible that if the heavy hydrocarbon composition is very small,such components will be adsorbed in the first 132′/132″ removal stage.This is also dependent on the composition of the adsorbent beds in thefirst 132′/132″ removal stage. However, if the heavy hydrocarbon contentis large, such as greater than 3 to 5 percent, then a separate,dedicated adsorption stage 134 is desirable. Upon saturation, heavyhydrocarbons are released through line 133.

It is preferred that the adsorbent bed in stage 134 be a zeolitematerial. Non-limiting examples of zeolites having appropriate poresizes for the removal of heavy hydrocarbons include MFI, faujasite,MCM-41 and Beta. It is preferred that the Si/Al ratio of zeolitesutilized in an embodiment of a process of the present invention forheavy hydrocarbon removal be from about 20 to about 1,000, preferablyfrom about 200 to about 1,000 in order to prevent excessive fouling ofthe adsorbent.

Molecular sieve beds fabricated from zeolite may be most effective atremoving C₂ to C₄ components, while silica gel beds may be mosteffective at removing C₅+ heavy hydrocarbons. Additional technicalinformation about the use of adsorptive kinetic separation for theseparation of hydrocarbon gas components is provided in U.S. Pat. Publ.No. 2008/0282884 entitled “Removal of Heavy Hydrocarbons From GasMixtures Containing Heavy Hydrocarbons and Methane.” This patentpublication is also incorporated herein by reference in its entirety.

As noted, the separated heavy hydrocarbons will be released through line133. The heavy hydrocarbons can be sold as a commercial fuel product.Alternatively, the heavy hydrocarbons may undergo some cooling tocondense out the heavier components and to reclaim any methane vapor.

The gas stream next moves to the third stage 136. The third stage 136provides for the removal of sulfurous components. Sulfurous componentsmay include hydrogen sulfide, sulfur dioxide, and mercaptans. The sourgas components are adsorbed onto the adsorbent bed, while methane ispassed on to an optional fourth stage 138. Upon saturation, thesulfurous components are released through line 135.

Where a dehydrated gas stream contains hydrogen sulfide, it may beadvantageous to formulate the adsorbent with stannosilicates.Specifically, 8-ring zeolites may be fabricated with stannosilicates.The kinetic selectivity of this class of 8-ring materials allows H₂S tobe rapidly transmitted into zeolite crystals. Upon saturation, the bedis purged. It is understood that the sulfurous components willpreferably be taken through a subsequent sulfur recovery process.

An optional fourth stage 138 is also provided in the gas separation unit130. The fourth stage 138 provides for the removal of carbon dioxide andnitrogen from the gas stream. CO₂ and N₂ are adsorbed onto the adsorbentbed of stage 138, while a sweetened gas stream is released. Uponpurging, CO₂ and N₂ exit the gas separation unit 130 through exit line137. At the same time, the sweetened gas stream is released through line140.

It is understood that the gas separation unit 130 may have fewer or morethan four stages. The number of AKS stages is dependent on thecomposition of the raw gas stream entering through gas line 122. Forexample, if the raw gas stream in gas line 122 has less than 0.5 ppm byvolume H₂S, then an adsorption stage for sulfurous components removallikely will not be required. Reciprocally, if the raw gas stream in gasline 122 has metal contaminants such as mercury, then a separate AKSstage will be added for such separation.

As noted, each stage 132′/132″, 134, 136, 138 will employ an adsorbentbed. Each adsorbent bed may represent an adsorbent bed system thatrelies on a plurality of beds in parallel. These beds may be packed, forexample, with activated carbons or molecular sieves. A first bed in eachsystem is used for adsorption. This is known as a service bed. A secondbed undergoes regeneration, such as through pressure reduction while thefirst bed is in service. Yet a third bed has already been regeneratedand is held in reserve for use in the adsorption system when the firstbed becomes substantially saturated. Thus, a minimum of three beds maybe used in parallel for a more efficient operation.

In each stage 132′/132″, 134, 136, 138, the service bed may be in itsown dedicated vessel, with the vessels of each stage being in series.Alternatively, the service beds may by aligned in series within one ormore combined vessels. It is also noted that the beds may be fabricatedfrom materials that will adsorb more than one component at a time. Forexample, a single bed may be designed to preferentially remove bothsulfurous components and carbon dioxide. Alternatively, two separatevessels may be provided in series that are designed to removesubstantially the same component. For example, if the raw gas stream ingas line 122 has a high CO₂ content, then two beds may be provided insequential vessels for preferential removal of the CO₂.

A combination of different types of adsorbent beds may be used fromstage to stage. Using a combination of adsorbent beds helps to preventheavy hydrocarbons from remaining in the gas phase and ultimately endingup with the methane-rich gas stream 140. In any arrangement, amethane-rich gas 140 is released from the gas separation unit 130.

The gas processing facility 100 also provides for the liquefaction ofthe natural gas. In the present context, this means that the sweetened,methane-rich gas stream 140 will be chilled. In FIG. 1, a liquefactionfacility is shown at 150.

Before entering the liquefaction facility 150, the methane-rich gasstream 140 may undergo modest compression. This is particularly truewhere there is a distance between the gas separation unit 130 and theliquefaction facility 150. In the facility 100 of FIG. 1, an optionalcompressor is shown at 145. The compressor 145 releases a compressedmethane-rich gas stream 142 that feeds into the liquefaction facility150.

In the present inventions, the liquefaction facility 150 is ahigh-pressure, expander-based facility. FIG. 5 presents a schematic flowdiagram of the high-pressure expander cycle refrigeration system 150, inone embodiment.

The refrigeration system 150 first includes a first compression unit515. Upon entering the liquefaction facility 150, the sweetenedmethane-rich gas stream 140 (or 142) is passed through the firstcompression unit 515. The first compression unit 515 may be, forexample, a high pressure centrifugal dry seal compressor. The firstcompression unit 515 will increase the pressure of the methane-rich gasstream 140 to a pressure greater than 1,000 psia (6,895 kPa). In thisway, a compressed gas feed stream 517 is created.

The liquefaction facility 150 also includes one or more compact heatexchangers for cooling the sweetened and compressed gas stream 517. Inthe arrangement of FIG. 5, first 525 and second 535 heat exchangers areshown. The liquefaction facility 150 also employs one or more highpressure expanders for further cooling. In FIG. 5, an expander is shownat 540.

The expander 540 may be of several types. For example, a Joule-Thompsonvalve may be used. Alternatively, a turbo-expander may be provided. Aturbo-expander is a centrifugal or axial flow turbine through which ahigh pressure gas is expanded. Turbo-expanders are typically used toproduce work that may be used, for example, to drive a compressor. Inthis respect, turbo-expanders create a source of shaft work forprocesses like compression or refrigeration. In any embodiment, aliquefied natural gas, or LNG stream, is produced. An LNG stream isshown at line 542.

As noted, the liquefaction facility 150 includes a first heat exchanger525. The heat exchanger 525 is part of a first refrigeration loop 520,and may be referred to as a first cooler. The first cooler 525 receivesthe compressed gas feed stream 517 from the first compression unit 515.The first cooler 525 then chills the compressed gas feed stream 517 downto a substantially chilled temperature. For example, the temperature maybe as low as −100° C. (−148° F.).

The first cooler 525 releases a compressed, cooled gaseous feed stream522. The compressed, cooled gaseous feed stream 522 is directed into thefirst expander 540. This serves to further cool the compressed gas feedstream 517 down to a temperature at which substantial liquefaction ofmethane takes place. Thus, a liquefied product stream 542 that is atleast about −162° C. (−260° F.) is released.

The product stream 542 will have a large liquid fraction and a remainingsmall vapor fraction. Therefore, it is preferred that the liquefactionfacility 150 also include a liquid separation vessel 550. The liquidseparation vessel 550 is configured to separate the liquid fraction andthe remaining vapor fraction. Thus, a liquid methane stream 152 isreleased in one line as the LNG commercial product, and a separate coldvapor stream 552 is released overhead.

The cold vapor stream 552 may be used as a coolant for the first cooler525 in the first refrigeration loop 520. It can be seen in FIG. 5 thatthe cold vapor stream 552 enters the first cooler 525 where heatexchange takes place with the compressed gas feed stream 517. Apartially-warmed product stream 554 is then released.

The partially-warmed product stream 554 is directed back to thebeginning of the first refrigeration loop 520. This means that thepartially-warmed product stream 554 is merged back with the methane-richgas stream 140 (or 142). To accomplish this, a third compression unit555 is provided. The third compression unit 555 releases a compressed,partially-warmed product stream 557. The compressed, partially-warmedproduct stream 557 is preferably taken through the first compressionunit 515 with the methane-rich gas stream 142.

It is preferred that the gas liquefaction facility 150 include a secondheat exchanger. The second heat exchanger is shown at 535, andrepresents a second cooler. The second heat exchanger 535 may optionallybe placed in line in the first refrigeration loop 520 after the firstcooler 525. In this way, the second heat exchanger 535 would providesub-cooling to the compressed, cooled gaseous feed stream 522. However,it is preferred that the second heat exchanger 535 be placed in line inthe first refrigeration loop 520 before the first cooler 525. This isthe arrangement shown in FIG. 5.

In FIG. 5, the second heat exchanger 535, or second cooler, receives thepartially-warmed product stream 554 from the first cooler 525. Indirectheat exchange then takes place between the partially-warmed productstream 554 and the compressed gas feed stream 517. The heat exchanger535 pre-cools the compressed gas feed 517 stream before the compressedgas feed stream 517 enters the first cooler 525. The second heatexchanger 535 thus releases a pre-cooled compressed gas feed stream 532into the first cooler 525.

The heat exchanger 535 also releases a warmed product stream 556. Inthis arrangement, the warmed product stream 556 enters the thirdcompression unit 555, and is released as the compressed andpartially-warmed product stream 557 that is merged with the methane-richgas stream 142.

In order to provide effective pre-cooling in the second cooler 535, itis desirable to employ a coolant in addition to the partially-warmedproduct stream 554. Therefore, a second refrigeration loop 530 is alsoprovided. The second refrigeration loop 530 employs a refrigerant,indicated at line 534. The refrigerant in line 534 is preferably anitrogen gas, or a nitrogen-containing gas. The use of nitrogen in therefrigerant expands the pre-cooling temperature regime.

Referring back to FIG. 1, it can be seen that a portion of thecontaminant from stage 138 is intercepted. This represents N₂ and,perhaps, some CO₂ in line 137. The nitrogen is taken via line 147 to thegas liquefaction facility 150. In addition, the operator may take aportion of the methane-rich gas stream 140 to use as the refrigerant534. This is done via line 141. Alternatively or in addition, theoperator may take a portion of the heavy hydrocarbons separated fromstage 136. The ethane (or other heavy hydrocarbons) is taken from line133 via line 143. Lines 141, 143, and 147 are shown as dashed lines,indicating optional fluid interceptions.

The gas components in lines 141, 143, and 147 are selectively andoptionally taken from the gas separation unit 130 and merged into line149. This is shown in FIG. 1. The components from lines 141, 143, and/or147 are then directed through line 149 into the second refrigerationloop 530. This is shown in FIG. 5. Valve 501 is seen for controlling theflow of components from lines 141, 143, and/or 147 through line 149 intothe second refrigeration loop 530. Valve 501 may also be used to diverta portion of the components from lines 141, 143, 147 for burning in agas turbine to generate electricity or for regenerating a bed inconnection with TSA.

It is, of course, understood that additional valving (not shown) willcontrol the relative volumes of the components in lines 141, 143, 147taken into line 149. It is further understood that the operator may drawfrom a dedicated tank of nitrogen (not shown) for the refrigerant inline 534. In any arrangement, the refrigerant from line 534 leaves theheat exchanger 535 in a warmed state. The refrigerant moves through asecond compression unit 536 for pressure boosting, and is then takenthrough an expander 538 for re-cooling. The refrigerant in line 534 thenre-enters the heat exchanger 535. A small chiller (not shown) may beadded to the second refrigeration loop 530 after the expander 538 tofurther cool the refrigerant in line 534.

It is noted that the heat exchanger 535 may serve as the only cooler forthe gas liquefaction facility 150. In this arrangement, the first cooler525 would not be used. Further, the vapor portion 552 would preferablythen be used as at least a portion of the refrigerant for line 534.However, the use of the heat exchanger 535 with the expander 538 in thesecond refrigeration loop 530 improves the overall cooling efficiency ofthe first expander loop 520. In any instance, the present invention isnot limited by the specific arrangement of coolers or refrigerationloops unless so expressly stated in the claims.

FIG. 6 is a flow chart showing steps for a process 600 for liquefying araw natural gas stream. The process 600 employs adsorptive kineticseparation to produce a methane-rich gas stream. The process 600 thenfurther utilizes a high-pressure expander cycle refrigeration system tochill the methane and to provide an LNG product. The LNG product ispreferably generated on a floating platform or a gravity-based platformoffshore.

The process 600 first includes receiving the natural gas feed stream ata gas separation unit. The gas separation unit has one or morefractionation vessels. The fractionation vessels are designed inaccordance with the fraction vessels described above in their variousembodiments. The fractionation vessels preferably operate on pressureswing adsorption (PSA) or rapid cycle pressure swing adsorption (RCPSA)to regenerate a series of adsorption beds. The adsorption beds aredesigned to adsorb CO₂, H₂S, H₂O, heavy hydrocarbons, VOC's, mercaptans,nitrogen, or combinations thereof.

The process 600 also includes substantially separating methane fromcontaminants within the natural gas feed stream. As a first separationstep, the raw natural gas feed stream is optionally taken through adehydration vessel. This serves to remove a substantial portion of waterand other liquid phase components from the natural gas stream. The stepof separating liquid-phase components (primarily water) from gas phasecomponents is shown in Box 620. A dehydrated natural gas feed stream isthen released as a dehydrated natural gas feed stream.

Next, gas-phase contaminants are removed from the dehydrated raw gasstream. The step of separating methane from gas-phase contaminantswithin the natural gas feed stream is shown at Box 630. This step isdone through the use of adsorption beds in the one or more fractionationvessels. In one aspect, separating methane from contaminants isconducted through the gas separation unit at a pressure of at leastabout 500 pounds per square inch absolute (psia).

FIG. 7 is a flow chart showing steps 700 for separating contaminantsfrom the raw natural gas stream. The steps use adsorptive kineticseparation to create the methane-rich gas stream.

First, water is adsorbed from the natural gas feed stream. In thisrespect, an adsorptive bed having water-retentive properties isemployed. This step is shown in Box 710. As noted above, it is preferredthat the water removal stage simply be a “polishing” stage. This meansthat most water has already been removed or “knocked out” by a previousdehydration vessel (per the step of Box 620).

Where a dehydration vessel is used, the contaminants in the gas streamwill include a desiccant such as ethylene glycol. Accordingly, a nextstage in separating components involves the adsorption of the desiccant.This is provided in Box 720.

As shown in FIG. 7, various additional adsorptive stages may beundertaken for the removal of contaminants. These may include theremoval of sulfurous components (Box 730), the removal of carbon dioxideand/or nitrogen (Box 740), the removal of mercury or other metallicelements (Box 750), and the removal of heavy hydrocarbons (Box 760).Depending on how the adsorbent beds are designed, some of thesecomponents may be removed in a single combined stage. Further, the orderof contaminant removal as provided in the steps of Boxes 710 through 760may be changed, although it is highly preferred that water be removedfirst as shown in Box 710. Thus, the process 600 is not limited by theorder in which contaminants are removed in the steps 700 unless sostated in the claims herein.

In one aspect, a single vessel having a plurality of adsorbent bedsaligned in series is used. For example, the at least one fractionationvessel in the gas separation unit may comprise a vessel containing aplurality of adsorbent beds in series, such that:

a first adsorption bed is designed to primarily remove water and otherliquid components from the dehydrated natural gas feed stream;

a second adsorption bed is designed to primarily remove a desiccant fromthe dehydrated natural gas feed stream; and

a third vessel comprises an adsorption bed designed primarily for theremoval of a sour gas component from the dehydrated natural gas feedstream.

Additional vessels may be added to adsorb and separate different sourgases.

In another aspect, multiple vessels in series are employed, with thevessels being aligned with the flow of the dehydrated natural gas feedstream. Each vessel releases a progressively sweeter methane gas stream.For example,

a first vessel uses an adsorption bed designed for the removal of waterremaining in the dehydrated natural gas feed stream;

a second vessel uses an adsorption bed designed for the removal of adesiccant from the dehydrated natural gas feed stream; and

a third vessel uses an adsorption bed designed for the removal of a sourgas component from the dehydrated natural gas feed stream.

The sour gas component may be one or more sulfurous components.Alternatively, the sour gas component may be carbon dioxide.

As a result of the adsorption steps 700 in FIG. 7, a methane-rich gasstream is generated. This stream is released from the gas separationunit as a dehydrated natural gas feed stream. Accordingly, the process600 next includes releasing a dehydrated, methane-rich gas stream fromthe gas separation unit. This is indicated at Box 640.

The methane-rich gas stream is directed to the high-pressure expandercycle refrigeration system. This is seen at Box 650. The refrigerationsystem is in accordance with the refrigeration system 150 shown above inFIG. 5, and as described in any of its various embodiments. Thus, therefrigeration system preferably includes a first refrigeration loop forcycling the vapor portion of the product for use as a coolant in a firstcooler, and a second refrigeration loop for cycling anitrogen-containing gas as a refrigerant in a second cooler. The secondcooler may utilize both the nitrogen-based refrigerant and apartially-warmed methane gas from the first cooler as working fluids.

The process 600 also includes compressing the methane-rich gas stream.This is provided at Box 660. The gas stream is compressed to a pressurethat is greater than 1,000 psia (6,895 kPa) in order to form acompressed gas feed stream.

The process 600 next comprises cooling the compressed gas feed stream toform a compressed, cooled gaseous feed stream. This is seen at Box 670.The cooling step of Box 670 preferably involves taking the compressedgas feed stream through at least one heat exchanger within a firstrefrigeration loop 520. For example, the compressed gas feed stream maybe pre-chilled using the heat exchanger 535 (second cooler) of FIG. 5,and then further cooled using the first cooler 525 of FIG. 5.Optionally, the heat exchanger 535 (second cooler) may be placed in thefirst refrigeration loop 520 after the first cooler 525. In this way,the heat exchanger 535 sub-cools the compressed gas feed stream 517after the compressed gas feed stream 517 has passed through the firstcooler 525.

The first refrigeration loop 520 cycles coolant through at least oneheat exchanger (such as cooler 525), and then directs the used (warmed)coolant (554 and/or 556) to a compression unit 555. The compression unitcompresses the warmed coolant to about 1,500 to 3,500 psia (10,342 to24,132 kPa). More preferably, the compression unit compresses the warmedproduct stream to about 2,500 to 3,000 psia (17,237 to 20,684 kPa).

The second cooler 535 is preferably part of a second refrigeration loop530. The second cooler 535 is configured to cool the compressed gas feedstream 517 at least partially by indirect heat exchange between arefrigerant stream 534 and the compressed, gas feed stream. The secondrefrigeration loop 530 may also include a compression unit 536. Thecompression unit 536 is configured to re-compress the refrigerant streamafter the refrigerant stream passes through the second cooler 535. Thesecond refrigeration loop will also then include an expander. Theexpander receives the re-compressed, cooled refrigerant stream, andexpands the compressed, cooled refrigerant stream prior to returning itto the second cooler 535.

The process 600 also includes expanding the cooled, compressed, gaseousfeed stream 522. This is provided at Box 680. In one aspect, expandingthe cooled, compressed, gaseous feed stream 522 comprises reducing thepressure of the cooled, compressed, gaseous feed stream to a pressurebetween about 50 psia (345 kPa) and 450 psia (3103 kPa). Expansion ofthe cooled gaseous feed stream 522 forms the LNG product stream 542. Theproduct stream has a liquid fraction and a remaining vapor fraction.

The high-pressure expander cycle refrigeration system preferablyincludes a liquid separation vessel. The process then further comprisesseparating the liquid fraction and the remaining vapor fraction. Theliquid portion may then be loaded into a transport vessel. This isindicated at Box 690 of FIG. 6.

In order to demonstrate the utility of the process 600, and particularlythe step of removing nitrogen using an AKS system, certain data has beengenerated. This date is presented in Tables in connection with certainexamples, below.

EXAMPLES

The Tables below depict comparisons developed using an Aspen HYSYS®(version 2006) process simulator, a computer-aided design program fromAspen Technology, Inc., of Cambridge, Mass. In connection with theTables, the term “SCRS” is used. This term is an acronym for “SelectiveComponent Removal System,” and in this context refers to an AKSadsorptive system.

First, Table 2 illustrates the effect of removing nitrogen from thenatural gas stream prior to liquefaction. The comparison is with theconventional approach where the nitrogen is removed after thenitrogen-containing natural gas is liquefied using a distillationcolumn. The power saving (greater than 7%) achieved results in areduction of power generation equipment. This, in turn, translates intospace and weight reductions, thereby enabling offshore LNG production.

TABLE 2 Effect of N₂ Removal with SCRS on Liquefaction Horsepower FeedMolar LNG Product Specification Composition w/o SCRS w/ SCRS Nitrogen0.0431 0.0101 0.0053 Methane 0.9559 0.9888 0.9936 Ethane 0.0010 0.00110.0011 Liquefaction Power (%) 100 93.3 Note that the requiredspecifications on the LNG are handily achieved

Next, Table 3 is provided to illustrate the benefit of using ahigh-pressure expander cycle refrigeration system on processperformance. The thermal energy required to produce the LNG from anambient temperature of 100° F. is reduced as the feed pressure isincreased, up to 17% for a pressure of 4,000 psia. Conventional gasconditioning methods reduce the feed gas pressure below 1,000 psia.Therefore compression equipment and the associated compressionhorsepower are required to boost the feed pressure in order tocapitalize on the benefit of the reduced thermal energy at elevatedpressures. This offsets the liquefaction horsepower reduction benefits.

TABLE 3 Effect of Elevated Feed Gas Pressure on Refrigeration DutyRequirement Refrigeration Feed Gas Duty Refrigeration Duty Pressure(psia) (normalized) % Reduction 4,000 83.0 17.0 3,000 86.4 13.6 2,00091.5 8.5 1,000 98.4 1.6 800 100.0 0.0It has been discovered that operating the AKS-based gas separation unitat an elevated pressure preserves and even enhances these benefits.

Table 4 highlights the performance improvement using the inventiveseparation process. In the conventional approach, the benefit of theelevated feed gas pressure is achieved by adding feed gas compression:the energy associated with the pressure reduction from the wellheaddictated by the conventional solvent extraction gas treating method istypically wasted. The SCRS unit may be configured to preserve thewellhead pressure and thereby avoid the wasted energy resulting from theconventional approach.

TABLE 4 Effect of Elevated Feed Gas Pressure on Liquefaction PowerLiquefaction Power % Feed Gas Reduction Incremental % Pressure w/ FeedGas Improvement (psia) Compression w/o SCRS w/ SCRS 5,000 10.9 38.7 27.94,500 12.0 37.4 25.3 4,000 13.1 35.9 22.8 3,500 14.1 33.9 19.8 3,00015.0 32.0 17.0 2,500 15.0 28.8 13.8 2,000 14.3 24.3 10.0 1,500 10.5 16.05.5 1,250 7.6 10.5 2.9 1,000 0.0 0.0 0.0

It is believed that by using small, light-weight AKS separators to formthe gas separation unit, and by using a high-pressure expander cyclerefrigeration system, the equipment footprint and weight of the gasconditioning or treating facilities are reduced by 75%. This maytranslate into a 21% reduction in space and weight on a FLNG barge.Alternatively, the available space and weight may be used to increasethe capacity of the FLNG barge. The reduction therefore improves theeconomic viability of the gas commercialization project.

As can be seen, an improved gas processing facility for the liquefactionof a natural gas stream is provided. In one aspect, the facilitycomprises:

1. a gas separation unit, the gas separation unit having at least onefractionation vessel comprised of:

a gas inlet for receiving a natural gas mixture comprising methane,

an adsorbent material that has a kinetic selectivity for contaminantsover methane greater than 5, such that the contaminants becomekinetically adsorbed within the adsorbent material, and

a gas outlet for releasing a methane-rich gas stream; and

a high-pressure expander cycle refrigeration system comprised of:

-   -   a first compression unit configured to receive a substantial        portion of the methane-rich gas stream and to compress the        methane-rich gas stream to greater than about 1,000 psia (6,895        kPa), thereby providing a compressed gas feed stream;    -   a first cooler configured to cool the compressed gas feed stream        to form a compressed, cooled gaseous feed stream; and    -   a first expander configured to expand the cooled, compressed,        gaseous feed stream to form a product stream having a liquid        fraction and a remaining vapor fraction.        2. The gas processing facility of paragraph 1, wherein:

the first cooler is configured to receive a portion of the productstream from the first expander, and use the portion of the productstream to cool the compressed gas feed stream through heat exchange.

3. The gas processing facility of paragraph 1, wherein:

the first cooler is configured to use an external refrigerant stream tocool the compressed gas feed stream through heat exchange.

4. The gas processing facility of paragraph 1, wherein the high-pressureexpander cycle refrigeration system further comprises:

a liquid separation vessel configured to separate the liquid fractionand the remaining vapor fraction from the first expander.

5. The gas processing facility of paragraph 4, wherein:

the first cooler receives at least a portion of the vapor fraction, anduses the vapor fraction to cool the compressed gas feed stream throughheat exchange as part of a first refrigeration loop;

the first cooler releases (i) a chilled gas feed stream, and (ii) apartially-warmed product stream after heat-exchanging with thecompressed gas feed stream; and

the high-pressure expander cycle refrigeration system further comprises:

-   -   a second cooler configured to further cool the compressed gas        feed stream at least partially by indirect heat exchange with a        refrigerant stream and the vapor fraction; and    -   a second refrigeration loop having (i) a second compression unit        configured to re-compress the refrigerant stream after the        refrigerant stream passes through the second cooler, and (ii) a        second expander configured to receive the re-compressed        refrigerant stream, and expand the re-compressed refrigerant        stream prior to returning it to the second cooler.        6. The gas processing facility of paragraph 5, wherein the        high-pressure expander cycle refrigeration system further        comprises:

a third compression unit in the first refrigeration loop for compressingthe partially-warmed product stream after heat-exchanging with thecompressed gas feed stream; and

a line for merging the compressed, partially-warmed product stream withthe gas feed stream to complete the first refrigeration loop.

7. The gas processing facility of paragraph 5, wherein the second coolersub-cools the chilled gas feed stream after the chilled gas feed streamleaves the first cooler.8. The gas processing facility of paragraph 5, wherein the second coolerpre-cools the compressed gas feed stream before the compressed gas feedstream enters the first cooler.9. The gas processing facility of paragraph 8, wherein:

the second cooler receives the partially-warmed product stream from thefirst cooler for further heat-exchanging with the compressed gas feedstream; and

releases a warmed product stream to a third compression unit to completethe first refrigeration loop.

10. The gas processing facility of paragraph 1, wherein the facility islocated on (i) a floating platform, (ii) a gravity-based platform, or(iii) a ship-shaped vessel offshore.11. The gas processing facility of paragraph 1, wherein the at least onefractionation vessel in the gas separation unit operates on pressureswing adsorption (PSA) or rapid cycle pressure swing adsorption (RCPSA).12. The gas processing facility of paragraph 11, wherein the at leastone fractionation vessel is configured to adsorb CO₂, H₂S, H₂O, heavyhydrocarbons, VOC's, mercaptans, or combinations thereof.13. The gas processing facility of paragraph 12, further comprising:

a dehydration vessel configured to receive the natural gas feed streamand remove a substantial portion of water from the natural gas feedstream, and release a dehydrated natural gas feed stream to the at leastone fractionation vessel.

14. A process for liquefying a natural gas feed stream, comprising:

receiving the natural gas feed stream at a gas separation unit, the gasseparation unit having at least one fractionation vessel comprised of:

-   -   a gas inlet for receiving a natural gas mixture comprising        methane,    -   an adsorbent material that has a kinetic selectivity for        contaminants over methane greater than 5, such that the        contaminants become kinetically adsorbed within the adsorbent        material, and    -   a gas outlet configured to release a methane-rich gas stream;    -   substantially separating methane from contaminants within the        natural gas feed stream;    -   releasing a methane-rich gas stream from the gas separation        unit;    -   directing the methane-rich gas stream into a high-pressure        expander cycle refrigeration system;    -   compressing the methane-rich gas stream to a pressure that is        greater than 1,000 psia (6,895 kPa) in order to form a        compressed gas feed stream;    -   cooling the compressed gas feed stream to form a compressed,        cooled gaseous feed stream;    -   expanding the cooled, compressed, gaseous feed stream to form a        product stream having a liquid fraction and a remaining vapor        fraction; and    -   separating the vapor fraction from the liquid fraction.        15. The process of paragraph 14, wherein the high-pressure        expander cycle refrigeration system comprises:

a first compression unit configured to receive a substantial portion ofthe methane-rich gas stream and to generate the compressed gas feedstream;

a first cooler configured to cool the compressed gas feed stream to formthe compressed, cooled gaseous feed stream; and

a first expander configured to expand the cooled, compressed, gaseousfeed stream to form the product stream.

16. The process of paragraph 15, wherein cooling the compressed gas feedstream comprises:

delivering at least a portion of the vapor fraction from the productstream to the first cooler as part of a first refrigeration loop; and

heat-exchanging the vapor fraction of the product stream with thecompressed gas feed stream to cool the compressed gas feed stream.

17. The process of paragraph 16, wherein:

the high-pressure expander cycle refrigeration system further comprisesa liquid separation vessel; and

separating the vapor fraction from the liquid fraction is done using theliquid separation vessel.

18. The process of paragraph 17, further comprising:

releasing from the first cooler (i) a chilled gas feed stream as theproduct stream, and (ii) a partially-warmed product stream as a workingfluid;

directing the partially-warmed product stream to a third compressionunit; and

merging the compressed, partially-warmed product stream from the thirdcompression unit with the methane-rich gas stream to complete the firstrefrigeration loop.

19. The process of paragraph 18, wherein the high-pressure expandercycle refrigeration system further comprises:

a second cooler configured to further cool the compressed gas feedstream at least partially by indirect heat exchange between arefrigerant stream and the vapor fraction; and

a second refrigeration loop having (i) a second compression unitconfigured to re-compress the refrigerant stream after the refrigerantstream passes through the second cooler, and (ii) a second expanderconfigured to receive the compressed refrigerant stream, and expand thecompressed refrigerant stream prior to returning it to the secondcooler.

20. The process of paragraph 19, wherein the second cooler sub-cools thechilled gas feed stream after the chilled gas feed stream leaves thefirst cooler.21. The process of paragraph 19, wherein the second cooler pre-cools thecompressed gas feed stream before the compressed gas feed stream entersthe first cooler.22. The process of paragraph 1, wherein the facility is located on (i) afloating platform, (ii) a gravity-based platform, or (iii) a ship-shapedvessel offshore.23. The process of paragraph 22, wherein the at least one fractionationvessel in the gas separation unit operates on pressure swing adsorption(PSA) or rapid cycle pressure swing adsorption (RCPSA).24. The process of paragraph 23, wherein the at least one fractionationvessel is configured to adsorb CO₂, H₂S, H₂O, heavy hydrocarbons, VOC's,mercaptans, or combinations thereof25. The process of paragraph 22, further comprising:

passing the natural gas feed stream through a dehydration vessel inorder to remove a substantial portion of water from the natural gas feedstream; and

release a dehydrated natural gas feed stream to the at least onefractionation vessel for contaminant removal.

26. A method for liquefying a natural gas feed stream, comprising:

receiving the natural gas feed stream at a gas processing facility;

passing the natural gas feed stream through a dehydration vessel inorder to remove a substantial portion of water from the natural gas feedstream;

releasing a dehydrated natural gas feed stream to a gas separation unitas a dehydrated natural gas feed stream;

in the gas separation unit, passing the dehydrated natural gas feedstream through a series of adsorbent beds in order to separate methanegas from contaminants in the dehydrated natural gas feed stream usingadsorptive kinetic separation;

releasing a methane-rich gas stream from the gas separation unit;

directing the methane-rich gas stream into a high-pressure expandercycle refrigeration system;

compressing the methane-rich gas stream to a pressure that is greaterthan 1,000 psia (6,895 kPa) in order to form a compressed gas feedstream;

cooling the compressed gas feed stream to form a compressed, cooledgaseous feed stream;

expanding the cooled, compressed, gaseous feed stream to form a productstream having a liquid fraction and a remaining vapor fraction.

27. The method of paragraph 26, wherein the series of adsorbent bedscomprises:

a first adsorption bed for the removal of water remaining in thedehydrated natural gas feed stream;

a second adsorption bed designed primarily for the removal of adesiccant from the dehydrated natural gas feed stream; and

a third adsorption bed designed primarily for the removal of a sour gascomponent from the dehydrated natural gas feed stream.

28. The method of paragraph 27, wherein each of the adsorbent beds hasassociated with it two additional adsorbent beds to form three adsorbentbeds, with:

a first of the three adsorbent beds being in service for adsorbing aselected contaminant;

a second of the three adsorbent beds undergoing regeneration; and

a third of the adsorbent beds being held in reserve to replace the firstof the three adsorbent beds; and

wherein the regeneration is part of a pressure-swing adsorption process.

As can be seen, another enhanced gas processing facility for theliquefaction of a natural gas stream is provided. In one aspect, thefacility comprises:

1A. A gas processing facility for the liquefaction of a natural gas feedstream, the facility comprising:

a gas separation unit, the gas separation unit having at least onefractionation vessel comprised of:

a gas inlet for receiving a natural gas mixture comprising methane,

an adsorbent material that has a kinetic selectivity for contaminantsover methane greater than 5, such that the contaminants becomekinetically adsorbed within the adsorbent material, and

a gas outlet for releasing a methane-rich gas stream; and

a high-pressure expander cycle refrigeration system comprised of:

a first compression unit configured to receive a substantial portion ofthe methane-rich gas stream and to compress the methane-rich gas streamto greater than about 1,000 psia (6,895 kPa), thereby providing acompressed gas feed stream;

a first cooler configured to cool the compressed gas feed stream to forma compressed, cooled gaseous feed stream; and

a first expander configured to expand the cooled, compressed, gaseousfeed stream to form a product stream having a liquid fraction and aremaining vapor fraction.

2A. The gas processing facility of paragraph 1A, wherein:

the first cooler is configured to receive a portion of the productstream from the first expander, and use the portion of the productstream to cool the compressed gas feed stream through heat exchange.

3A. The gas processing facility of paragraph 1A, wherein:the first cooler is configured to use an external refrigerant stream tocool the compressed gas feed stream through heat exchange.4A. The gas processing facility of paragraph 1A, wherein thehigh-pressure expander cycle refrigeration system further comprises:

a liquid separation vessel configured to separate the liquid fractionand the remaining vapor fraction from the first expander.

5A. The gas processing facility of paragraph 4A, wherein:

the first cooler receives at least a portion of the vapor fraction, anduses the vapor fraction to cool the compressed gas feed stream throughheat exchange as part of a first refrigeration loop;

the first cooler releases (i) a chilled gas feed stream, and (ii) apartially-warmed product stream after heat-exchanging with thecompressed gas feed stream; and

the high-pressure expander cycle refrigeration system further comprises:

a second cooler configured to further cool the compressed gas feedstream at least partially by indirect heat exchange with a refrigerantstream and the vapor fraction; and

a second refrigeration loop having (i) a second compression unitconfigured to re-compress the refrigerant stream after the refrigerantstream passes through the second cooler, and (ii) a second expanderconfigured to receive the re-compressed refrigerant stream, and expandthe re-compressed refrigerant stream prior to returning it to the secondcooler.

6A. The gas processing facility of paragraph 5A, wherein thehigh-pressure expander cycle refrigeration system further comprises:

a third compression unit in the first refrigeration loop for compressingthe partially-warmed product stream after heat-exchanging with thecompressed gas feed stream; and

a line for merging the compressed, partially-warmed product stream withthe gas feed stream to complete the first refrigeration loop.

7A. The gas processing facility of paragraph 5A, wherein the secondcooler sub-cools the chilled gas feed stream after the chilled gas feedstream leaves the first cooler.8A. The gas processing facility of paragraph 5A, wherein the secondcooler pre-cools the compressed gas feed stream before the compressedgas feed stream enters the first cooler.9A. The gas processing facility of paragraph 8A, wherein:

the second cooler receives the partially-warmed product stream from thefirst cooler for further heat-exchanging with the compressed gas feedstream; and

releases a warmed product stream to a third compression unit to completethe first refrigeration loop.

10A. The gas processing facility of paragraph 9A, wherein the thirdcompression unit compresses the warmed product stream to about 1,500 to3,500 psia (10,342 to 24,132 kPa).11A. The gas processing facility of paragraph 1A, wherein the facilityis located on (i) a floating platform, (ii) a gravity-based platform, or(iii) a ship-shaped vessel offshore.12A. The gas processing facility of paragraph 5A, wherein:

the refrigerant stream comprises a gas selected from the groupconsisting of: nitrogen gas, nitrogen-containing gas, a side stream fromthe methane-rich gas stream, and the remaining vapor fraction, andcombinations thereof; and

the refrigerant stream in the second refrigeration loop flows in aclosed loop.

13A. The gas processing facility of paragraph 1A, wherein the at leastone fractionation vessel in the gas separation unit operates on pressureswing adsorption (PSA) or rapid cycle pressure swing adsorption (RCPSA).14A. The gas processing facility of paragraph 13A, wherein the at leastone fractionation vessel in the gas separation unit further operates ontemperature swing adsorption (TSA) or rapid cycle temperature swingadsorption (RCTSA).15A. The gas processing facility of paragraph 13A, wherein the at leastone fractionation vessel is configured to adsorb CO₂, H₂S, H₂O, heavyhydrocarbons, VOC's, mercaptans, or combinations thereof.16A. The gas processing facility of paragraph 13A, wherein each of theat least one fractionation vessel cooperates with other fractionationvessels to form a pressure swing adsorption system comprising:

at least one service bed providing adsorption,

at least one bed in regeneration undergoing pressure reduction, and

at least one regenerated bed held in reserve for use in the adsorptionsystem when the at least one service bed becomes substantiallysaturated.

17A. The gas processing facility of paragraph 13A, further comprising:

a dehydration vessel configured to receive the natural gas feed streamand remove a substantial portion of water from the natural gas feedstream, and release a dehydrated natural gas feed stream to the at leastone fractionation vessel.

18A. The gas processing facility of paragraph 17A, wherein the at leastone fractionation vessel in the gas separation unit comprises aplurality of vessels in series, such that:

a first vessel comprises an adsorption bed for the removal of waterremaining in the dehydrated natural gas feed stream;

a second vessel comprises an adsorption bed designed primarily for theremoval of a desiccant from the dehydrated natural gas feed stream; and

a third vessel comprises an adsorption bed designed primarily for theremoval of a sour gas component from the dehydrated natural gas feedstream.

19A. The gas processing facility of paragraph 17A, wherein the at leastone fractionation vessel in the gas separation unit comprises a vesselcontaining a plurality of adsorbent beds in series, such that:

a first adsorption bed is designed to primarily remove water and otherliquid components from the dehydrated natural gas feed stream;

a second adsorption bed is designed to primarily remove a desiccant fromthe dehydrated natural gas feed stream; and

a third vessel comprises an adsorption bed primarily for the removal ofa sour gas component from the dehydrated natural gas feed stream.

20A. A process for liquefying a natural gas feed stream, comprising:

receiving the natural gas feed stream at a gas separation unit, the gasseparation unit having at least one fractionation vessel comprised of:

a gas inlet for receiving a natural gas mixture comprising methane,

an adsorbent material that has a kinetic selectivity for contaminantsover methane greater than 5, such that the contaminants becomekinetically adsorbed within the adsorbent material, and

a gas outlet configured to release a methane-rich gas stream;

substantially separating methane from contaminants within the naturalgas feed stream;

releasing a methane-rich gas stream from the gas separation unit;

directing the methane-rich gas stream into a high-pressure expandercycle refrigeration system;

compressing the methane-rich gas stream to a pressure that is greaterthan 1,000 psia (6,895 kPa) in order to form a compressed gas feedstream;

cooling the compressed gas feed stream to form a compressed, cooledgaseous feed stream;

expanding the cooled, compressed, gaseous feed stream to form a productstream having a liquid fraction and a remaining vapor fraction; and

separating the vapor fraction from the liquid fraction.

21A. The process of paragraph 20A, wherein the high-pressure expandercycle refrigeration system comprises:

a first compression unit configured to receive a substantial portion ofthe methane-rich gas stream and to generate the compressed gas feedstream;

a first cooler configured to cool the compressed gas feed stream to formthe compressed, cooled gaseous feed stream; and

a first expander configured to expand the cooled, compressed, gaseousfeed stream to form the product stream.

22A. The process of paragraph 21A, wherein cooling the compressed gasfeed stream comprises:

delivering at least a portion of the vapor fraction from the productstream to the first cooler as part of a first refrigeration loop; and

heat-exchanging the vapor fraction of the product stream with thecompressed gas feed stream to cool the compressed gas feed stream.

23A. The process of paragraph 22A, wherein:

the high-pressure expander cycle refrigeration system further comprisesa liquid separation vessel; and

separating the vapor fraction from the liquid fraction is done using theliquid separation vessel.

24A. The process of paragraph 23A, further comprising:

releasing from the first cooler (i) a chilled gas feed stream as theproduct stream, and (ii) a partially-warmed product stream as a workingfluid;

directing the partially-warmed product stream to a third compressionunit; and

merging the compressed, partially-warmed product stream from the thirdcompression unit with the methane-rich gas stream to complete the firstrefrigeration loop.

25A. The process of paragraph 24A, wherein the high-pressure expandercycle refrigeration system further comprises:

a second cooler configured to further cool the compressed gas feedstream at least partially by indirect heat exchange between arefrigerant stream and the vapor fraction; and

a second refrigeration loop having (i) a second compression unitconfigured to re-compress the refrigerant stream after the refrigerantstream passes through the second cooler, and (ii) a second expanderconfigured to receive the compressed refrigerant stream, and expand thecompressed refrigerant stream prior to returning it to the secondcooler.

26A. The process of paragraph 25A, wherein the second cooler sub-coolsthe chilled gas feed stream after the chilled gas feed stream leaves thefirst cooler.27A. The process of paragraph 25A, wherein the second cooler pre-coolsthe compressed gas feed stream before the compressed gas feed streamenters the first cooler.28A. The process of paragraph 23A, wherein the facility is located on(i) a floating platform, (ii) a gravity-based platform, or (iii) aship-shaped vessel offshore.29A. The process of paragraph 23A, wherein the at least onefractionation vessel in the gas separation unit operates on pressureswing adsorption (PSA) or rapid cycle pressure swing adsorption (RCPSA).30A. The process of paragraph 23A, wherein the at least onefractionation vessel in the gas separation unit further operates ontemperature swing adsorption (TSA) or rapid cycle temperature swingadsorption (RCTSA).31A. The process of paragraph 30A, wherein the at least onefractionation vessel is configured to adsorb CO₂, H₂S, H₂O, heavyhydrocarbons, VOC's, mercaptans, or combinations thereof32A. The process of paragraph 31A, further comprising:

passing the natural gas feed stream through a dehydration vessel inorder to remove a substantial portion of water from the natural gas feedstream; and

release a dehydrated natural gas feed stream to the at least onefractionation vessel for contaminant removal.

33A. The process of paragraph 32A, wherein the at least onefractionation vessel in the gas separation unit comprises a plurality ofvessels in series, such that:

a first vessel comprises an adsorption bed for the removal of waterremaining in the dehydrated natural gas feed stream;

a second vessel comprises an adsorption bed designed primarily for theremoval of a desiccant from the dehydrated natural gas feed stream; and

a third vessel comprises an adsorption bed designed primarily for theremoval of a sour gas component from the dehydrated natural gas feedstream.

34A. The process of paragraph 32A, wherein the at least onefractionation vessel in the gas separation unit comprises a vesselcontaining a plurality of adsorbent beds in series, such that:

a first adsorption bed is designed to primarily remove water and otherliquid components from the dehydrated natural gas feed stream;

a second adsorption bed is designed to primarily remove a desiccant fromthe dehydrated natural gas feed stream; and

a third vessel comprises an adsorption bed designed primarily for theremoval of a sour gas component from the dehydrated natural gas feedstream.

35A. A method for liquefying a natural gas feed stream, comprising:

receiving the natural gas feed stream at a gas processing facility;

passing the natural gas feed stream through a dehydration vessel inorder to remove a substantial portion of water from the natural gas feedstream;

releasing a dehydrated natural gas feed stream to a gas separation unitas a dehydrated natural gas feed stream;

in the gas separation unit, passing the dehydrated natural gas feedstream through a series of adsorbent beds in order to separate methanegas from contaminants in the dehydrated natural gas feed stream usingadsorptive kinetic separation;

releasing a methane-rich gas stream from the gas separation unit;

directing the methane-rich gas stream into a high-pressure expandercycle refrigeration system;

compressing the methane-rich gas stream to a pressure that is greaterthan 1,000 psia (6,895 kPa) in order to form a compressed gas feedstream;

cooling the compressed gas feed stream to form a compressed, cooledgaseous feed stream;

expanding the cooled, compressed, gaseous feed stream to form a productstream having a liquid fraction and a remaining vapor fraction.

36A. The method of paragraph 35A, wherein the series of adsorbent bedscomprises:

a first adsorption bed for the removal of water remaining in thedehydrated natural gas feed stream;

a second adsorption bed designed primarily for the removal of adesiccant from the dehydrated natural gas feed stream; and

a third adsorption bed designed primarily for the removal of a sour gascomponent from the dehydrated natural gas feed stream.

37A. The method of paragraph 36A, wherein the first, second, and thirdadsorption beds are aligned in series with flow of the dehydratednatural gas feed stream in a single pressure vessel.38A. The method of paragraph 36A, wherein the first, second, and thirdadsorption beds reside in separate pressure vessels that are aligned inseries with the flow of the dehydrated natural gas feed stream.39A. The method of paragraph 36A, wherein each of the adsorbent bedscomprises a solid adsorbent bed fabricated from a zeolite material.40A. The method of paragraph 37A, wherein each of the adsorbent beds hasassociated with it two additional adsorbent beds to form three adsorbentbeds, with:

a first of the three adsorbent beds being in service for adsorbing aselected contaminant;

a second of the three adsorbent beds undergoing regeneration; and

a third of the adsorbent beds being held in reserve to replace the firstof the three adsorbent beds; and wherein

the regeneration is part of a pressure-swing adsorption process.

41A. The method of paragraph 36A, wherein cooling the compressed gasfeed stream comprises:

passing the compressed gas feed stream through a first heat exchanger inorder to provide heat exchange with a cooled refrigerant stream, therebyforming a sub-cooled gas feed stream; and

passing the sub-cooled gas feed stream through a second heat exchangerin order to provide heat exchange with a cooling gas stream, therebyforming the compressed, cooled gaseous feed stream.

42A. The method of paragraph 41A, further comprising:

withdrawing a portion of the remaining vapor fraction from the productstream;

reducing the pressure of the withdrawn portion of the remaining vaporfraction down to a pressure of about 30 to 200 psia (207 to 1,379 kPa)to produce a reduced pressure gas stream;

passing the reduced pressure gas stream through the second heatexchanger as the cooling gas stream; and

releasing the reduced pressure gas stream from the second heat exchangeras a partially-warmed gas stream.

43A. The method of paragraph 42A, further comprising:

passing the partially-warmed gas stream through the first heat exchangeras a cooling gas stream; and

returning the partially-warmed gas stream to the dehydrated natural gasfeed stream for compressing with the methane-rich gas stream.

44A. The method of paragraph 36A, wherein:

compressing the methane-rich gas stream comprises compressing themethane-rich gas stream to a pressure that is between about 1,200 psia(8,274 kPa) to 4,500 psia (31,026 kPa); and

expanding the cooled, compressed, gaseous feed stream comprises reducingthe pressure of the cooled, compressed, gaseous feed stream to apressure between about 50 psia (345 kPa) and 450 psia (3,103 kPa).

As can be seen, processes, systems and methods for liquefying a naturalgas feed stream using AKS and a high-pressure expander cyclerefrigeration system are provided. Such processes, systems and methodsallow for the formation of LNG using a facility having less weight thanconventional facilities. The processes, systems and methods also permitrapid tool-up for offshore production operations. The inventionsdescribed herein are not restricted to the specific embodiment disclosedherein, but are governed by the claims, which follow. While it will beapparent that the inventions herein described are well calculated toachieve the benefits and advantages set forth above, it will beappreciated that the inventions are susceptible to modification,variation and change without departing from the spirit thereof.

What is claimed is:
 1. A gas processing facility for the liquefaction ofa natural gas feed stream, the facility comprising: a gas separationunit, the gas separation unit having at least one fractionation vesselcomprised of: a gas inlet for receiving a natural gas mixture comprisingmethane, an adsorbent material that has a kinetic selectivity forcontaminants over methane greater than 5, such that the contaminantsbecome kinetically adsorbed within the adsorbent material, and a gasoutlet for releasing a methane-rich gas stream; and a high-pressureexpander cycle refrigeration system comprised of: a first compressionunit configured to receive a substantial portion of the methane-rich gasstream and to compress the methane-rich gas stream to greater than about1,000 psia (6,895 kPa), thereby providing a compressed gas feed stream;a first cooler configured to cool the compressed gas feed stream to forma compressed, cooled gaseous feed stream; and a first expanderconfigured to expand the cooled, compressed, gaseous feed stream to forma product stream having a liquid fraction and a remaining vaporfraction.
 2. The gas processing facility of claim 1, wherein: the firstcooler is configured to receive a portion of the product stream from thefirst expander, and use the portion of the product stream to cool thecompressed gas feed stream through heat exchange.
 3. The gas processingfacility of claim 1, wherein: the first cooler is configured to use anexternal refrigerant stream to cool the compressed gas feed streamthrough heat exchange.
 4. The gas processing facility of claim 1,wherein the high-pressure expander cycle refrigeration system furthercomprises: a liquid separation vessel configured to separate the liquidfraction and the remaining vapor fraction from the first expander. 5.The gas processing facility of claim 4, wherein: the first coolerreceives at least a portion of the vapor fraction, and uses the vaporfraction to cool the compressed gas feed stream through heat exchange aspart of a first refrigeration loop; the first cooler releases (i) achilled gas feed stream, and (ii) a partially-warmed product streamafter heat-exchanging with the compressed gas feed stream; and thehigh-pressure expander cycle refrigeration system further comprises: asecond cooler configured to further cool the compressed gas feed streamat least partially by indirect heat exchange with a refrigerant streamand the vapor fraction; and a second refrigeration loop having (i) asecond compression unit configured to re-compress the refrigerant streamafter the refrigerant stream passes through the second cooler, and (ii)a second expander configured to receive the re-compressed refrigerantstream, and expand the re-compressed refrigerant stream prior toreturning it to the second cooler.
 6. The gas processing facility ofclaim 5, wherein the high-pressure expander cycle refrigeration systemfurther comprises: a third compression unit in the first refrigerationloop for compressing the partially-warmed product stream afterheat-exchanging with the compressed gas feed stream; and a line formerging the compressed, partially-warmed product stream with the gasfeed stream to complete the first refrigeration loop.
 7. The gasprocessing facility of claim 5, wherein the second cooler sub-cools thechilled gas feed stream after the chilled gas feed stream leaves thefirst cooler.
 8. The gas processing facility of claim 5, wherein thesecond cooler pre-cools the compressed gas feed stream before thecompressed gas feed stream enters the first cooler.
 9. The gasprocessing facility of claim 8, wherein: the second cooler receives thepartially-warmed product stream from the first cooler for furtherheat-exchanging with the compressed gas feed stream; and releases awarmed product stream to a third compression unit to complete the firstrefrigeration loop.
 10. The gas processing facility of claim 9, whereinthe third compression unit compresses the warmed product stream to about1,500 to 3,500 psia (10,342 to 24,132 kPa).
 11. The gas processingfacility of claim 1, wherein the facility is located on (i) a floatingplatform, (ii) a gravity-based platform, or (iii) a ship-shaped vesseloffshore.
 12. The gas processing facility of claim 5, wherein: therefrigerant stream comprises a gas selected from the group consistingof: nitrogen gas, nitrogen-containing gas, a side stream from themethane-rich gas stream, and the remaining vapor fraction, andcombinations thereof; and the refrigerant stream in the secondrefrigeration loop flows in a closed loop.
 13. The gas processingfacility of claim 1, wherein the at least one fractionation vessel inthe gas separation unit operates on pressure swing adsorption (PSA) orrapid cycle pressure swing adsorption (RCPSA).
 14. The gas processingfacility of claim 13, wherein the at least one fractionation vessel inthe gas separation unit further operates on temperature swing adsorption(TSA) or rapid cycle temperature swing adsorption (RCTSA).
 15. The gasprocessing facility of claim 13, wherein the at least one fractionationvessel is configured to adsorb CO₂, H₂S, H₂O, heavy hydrocarbons, VOC's,mercaptans, or combinations thereof.
 16. The gas processing facility ofclaim 13, wherein each of the at least one fractionation vesselcooperates with other fractionation vessels to form a pressure swingadsorption system comprising: at least one service bed providingadsorption, at least one bed in regeneration undergoing pressurereduction, and at least one regenerated bed held in reserve for use inthe adsorption system when the at least one service bed becomessubstantially saturated.
 17. The gas processing facility of claim 13,further comprising: a dehydration vessel configured to receive thenatural gas feed stream and remove a substantial portion of water fromthe natural gas feed stream, and release a dehydrated natural gas feedstream to the at least one fractionation vessel.
 18. The gas processingfacility of claim 17, wherein the at least one fractionation vessel inthe gas separation unit comprises a plurality of vessels in series, suchthat: a first vessel comprises an adsorption bed for the removal ofwater remaining in the dehydrated natural gas feed stream; a secondvessel comprises an adsorption bed designed primarily for the removal ofa desiccant from the dehydrated natural gas feed stream; and a thirdvessel comprises an adsorption bed designed primarily for the removal ofa sour gas component from the dehydrated natural gas feed stream. 19.The gas processing facility of claim 17, wherein the at least onefractionation vessel in the gas separation unit comprises a vesselcontaining a plurality of adsorbent beds in series, such that: a firstadsorption bed is designed to primarily remove water and other liquidcomponents from the dehydrated natural gas feed stream; a secondadsorption bed is designed to primarily remove a desiccant from thedehydrated natural gas feed stream; and a third vessel comprises anadsorption bed primarily for the removal of a sour gas component fromthe dehydrated natural gas feed stream.
 20. A process for liquefying anatural gas feed stream, comprising: receiving the natural gas feedstream at a gas separation unit, the gas separation unit having at leastone fractionation vessel comprised of: a gas inlet for receiving anatural gas mixture comprising methane, an adsorbent material that has akinetic selectivity for contaminants over methane greater than 5, suchthat the contaminants become kinetically adsorbed within the adsorbentmaterial, and a gas outlet configured to release a methane-rich gasstream; substantially separating methane from contaminants within thenatural gas feed stream; releasing a methane-rich gas stream from thegas separation unit; directing the methane-rich gas stream into ahigh-pressure expander cycle refrigeration system; compressing themethane-rich gas stream to a pressure that is greater than 1,000 psia(6,895 kPa) in order to form a compressed gas feed stream; cooling thecompressed gas feed stream to form a compressed, cooled gaseous feedstream; expanding the cooled, compressed, gaseous feed stream to form aproduct stream having a liquid fraction and a remaining vapor fraction;and separating the vapor fraction from the liquid fraction.
 21. Theprocess of claim 20, wherein the high-pressure expander cyclerefrigeration system comprises: a first compression unit configured toreceive a substantial portion of the methane-rich gas stream and togenerate the compressed gas feed stream; a first cooler configured tocool the compressed gas feed stream to form the compressed, cooledgaseous feed stream; and a first expander configured to expand thecooled, compressed, gaseous feed stream to form the product stream. 22.The process of claim 21, wherein cooling the compressed gas feed streamcomprises: delivering at least a portion of the vapor fraction from theproduct stream to the first cooler as part of a first refrigerationloop; and heat-exchanging the vapor fraction of the product stream withthe compressed gas feed stream to cool the compressed gas feed stream.23. The process of claim 22, wherein: the high-pressure expander cyclerefrigeration system further comprises a liquid separation vessel; andseparating the vapor fraction from the liquid fraction is done using theliquid separation vessel.
 24. The process of claim 23, furthercomprising: releasing from the first cooler (i) a chilled gas feedstream as the product stream, and (ii) a partially-warmed product streamas a working fluid; directing the partially-warmed product stream to athird compression unit; and merging the compressed, partially-warmedproduct stream from the third compression unit with the methane-rich gasstream to complete the first refrigeration loop.
 25. The process ofclaim 24, wherein the high-pressure expander cycle refrigeration systemfurther comprises: a second cooler configured to further cool thecompressed gas feed stream at least partially by indirect heat exchangebetween a refrigerant stream and the vapor fraction; and a secondrefrigeration loop having (i) a second compression unit configured tore-compress the refrigerant stream after the refrigerant stream passesthrough the second cooler, and (ii) a second expander configured toreceive the compressed refrigerant stream, and expand the compressedrefrigerant stream prior to returning it to the second cooler.
 26. Theprocess of claim 25, wherein the second cooler sub-cools the chilled gasfeed stream after the chilled gas feed stream leaves the first cooler.27. The process of claim 25, wherein the second cooler pre-cools thecompressed gas feed stream before the compressed gas feed stream entersthe first cooler.
 28. The process of claim 23, wherein the facility islocated on (i) a floating platform, (ii) a gravity-based platform, or(iii) a ship-shaped vessel offshore.
 29. The process of claim 23,wherein the at least one fractionation vessel in the gas separation unitoperates on pressure swing adsorption (PSA) or rapid cycle pressureswing adsorption (RCPSA).
 30. The process of claim 23, wherein the atleast one fractionation vessel in the gas separation unit furtheroperates on temperature swing adsorption (TSA) or rapid cycletemperature swing adsorption (RCTSA).
 31. The process of claim 30,wherein the at least one fractionation vessel is configured to adsorbCO₂, H₂S, H₂O, heavy hydrocarbons, VOC's, mercaptans, or combinationsthereof.
 32. The process of claim 31, further comprising: passing thenatural gas feed stream through a dehydration vessel in order to removea substantial portion of water from the natural gas feed stream; andrelease a dehydrated natural gas feed stream to the at least onefractionation vessel for contaminant removal.
 33. The process of claim32, wherein the at least one fractionation vessel in the gas separationunit comprises a plurality of vessels in series, such that: a firstvessel comprises an adsorption bed for the removal of water remaining inthe dehydrated natural gas feed stream; a second vessel comprises anadsorption bed designed primarily for the removal of a desiccant fromthe dehydrated natural gas feed stream; and a third vessel comprises anadsorption bed designed primarily for the removal of a sour gascomponent from the dehydrated natural gas feed stream.
 34. The processof claim 32, wherein the at least one fractionation vessel in the gasseparation unit comprises a vessel containing a plurality of adsorbentbeds in series, such that: a first adsorption bed is designed toprimarily remove water and other liquid components from the dehydratednatural gas feed stream; a second adsorption bed is designed toprimarily remove a desiccant from the dehydrated natural gas feedstream; and a third vessel comprises an adsorption bed designedprimarily for the removal of a sour gas component from the dehydratednatural gas feed stream.
 35. A method for liquefying a natural gas feedstream, comprising: receiving the natural gas feed stream at a gasprocessing facility; passing the natural gas feed stream through adehydration vessel in order to remove a substantial portion of waterfrom the natural gas feed stream; releasing a dehydrated natural gasfeed stream to a gas separation unit as a dehydrated natural gas feedstream; in the gas separation unit, passing the dehydrated natural gasfeed stream through a series of adsorbent beds in order to separatemethane gas from contaminants in the dehydrated natural gas feed streamusing adsorptive kinetic separation; releasing a methane-rich gas streamfrom the gas separation unit; directing the methane-rich gas stream intoa high-pressure expander cycle refrigeration system; compressing themethane-rich gas stream to a pressure that is greater than 1,000 psia(6,895 kPa) in order to form a compressed gas feed stream; cooling thecompressed gas feed stream to form a compressed, cooled gaseous feedstream; expanding the cooled, compressed, gaseous feed stream to form aproduct stream having a liquid fraction and a remaining vapor fraction.36. The method of claim 35, wherein the series of adsorbent bedscomprises: a first adsorption bed for the removal of water remaining inthe dehydrated natural gas feed stream; a second adsorption bed designedprimarily for the removal of a desiccant from the dehydrated natural gasfeed stream; and a third adsorption bed designed primarily for theremoval of a sour gas component from the dehydrated natural gas feedstream.
 37. The method of claim 36, wherein the first, second, and thirdadsorption beds are aligned in series with flow of the dehydratednatural gas feed stream in a single pressure vessel.
 38. The method ofclaim 36, wherein the first, second, and third adsorption beds reside inseparate pressure vessels that are aligned in series with the flow ofthe dehydrated natural gas feed stream.
 39. The method of claim 36,wherein each of the adsorbent beds comprises a solid adsorbent bedfabricated from a zeolite material.
 40. The method of claim 37, whereineach of the adsorbent beds has associated with it two additionaladsorbent beds to form three adsorbent beds, with: a first of the threeadsorbent beds being in service for adsorbing a selected contaminant; asecond of the three adsorbent beds undergoing regeneration; and a thirdof the adsorbent beds being held in reserve to replace the first of thethree adsorbent beds; and wherein the regeneration is part of apressure-swing adsorption process.
 41. The method of claim 36, whereincooling the compressed gas feed stream comprises: passing the compressedgas feed stream through a first heat exchanger in order to provide heatexchange with a cooled refrigerant stream, thereby forming a sub-cooledgas feed stream; and passing the sub-cooled gas feed stream through asecond heat exchanger in order to provide heat exchange with a coolinggas stream, thereby forming the compressed, cooled gaseous feed stream.42. The method of claim 41, further comprising: withdrawing a portion ofthe remaining vapor fraction from the product stream; reducing thepressure of the withdrawn portion of the remaining vapor fraction downto a pressure of about 30 to 200 psia (207 to 1,379 kPa) to produce areduced pressure gas stream; passing the reduced pressure gas streamthrough the second heat exchanger as the cooling gas stream; andreleasing the reduced pressure gas stream from the second heat exchangeras a partially-warmed gas stream.
 43. The method of claim 42, furthercomprising: passing the partially-warmed gas stream through the firstheat exchanger as a cooling gas stream; and returning thepartially-warmed gas stream to the dehydrated natural gas feed streamfor compressing with the methane-rich gas stream.
 44. The method ofclaim 36, wherein: compressing the methane-rich gas stream comprisescompressing the methane-rich gas stream to a pressure that is betweenabout 1,200 psia (8,274 kPa) to 4,500 psia (31,026 kPa); and expandingthe cooled, compressed, gaseous feed stream comprises reducing thepressure of the cooled, compressed, gaseous feed stream to a pressurebetween about 50 psia (345 kPa) and 450 psia (3,103 kPa).